OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY 

AIR QUALITY DIVISION 

MEMORANDUM September 9, 2010 

TO: Phillip Fielder, P.E., Permits and Engineering Group Manager 

 Air Quality Division 

THROUGH: Phil Martin, P.E., Engineering Section 

THROUGH: Peer Review 

FROM: Eric L. Milligan, P.E., Engineering Section 

SUBJECT: Evaluation of Permit Application No. 2005-037-TVR (M-2) 

Western Farmers Electric Cooperative 

Anadarko Power Plant (SIC 4911) 

NW/4 of Section 14, T7N, R10W, Caddo County 

Located 1 mile north of SH 62 and 7th Street in Anadarko

Latitude: 35.089° N; Longitude: 98.229° W 

SECTION I. INTRODUCTION

Western Farmers Electric Cooperative (WFEC) has requested an administrative amendment of 

their current permit (Permit No. 2005-037-TVR (M-1), issued on July 13, 2010) to modify 

Specific Condition 14 to include wording that excludes their current construction permit from 

becoming null and void. No other changes will be made to the memorandum or the specific 

conditions. 

WFEC current permit was for a modification to address the Best Available Retrofit Technology 

(BART) requirements contained in the regional haze program found in Title 40 Part 51, Subpart 

P, of the Clean Air Act and Oklahoma Administrative Code (OAC) 252, Subchapter 8, Part 11. 

Facilities with affected equipment were required to either submit an application for a waiver or 

exemption from BART by December 1, 2006, or to submit a BART determination by March 30, 

2007. However, facilities required to submit a permit application requesting enforceable limits 

to qualify for a waiver were granted until March 30, 2007, to submit an application. A facility 

can apply for a waiver if it can be demonstrated through modeling that the affected sources do 

not cause or contribute to visibility impairment in any mandatory Class I Federal area. These 

modeling thresholds are found in OAC 252:100-8-73. Facilities are required to be in compliance 

with any BART requirements within 5 years of EPA approval of the Oklahoma regional haze 

State Implementation Plan (SIP). 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 2 

WFEC conducted a review of the impacts on Class I areas by the affected sources at the 

Anadarko Power Plant. This review indicated that WFEC could control their affected equipment 

and apply enforceable limits in order to assure the affected sources do not cause or contribute to 

visibility impairment in any mandatory Class I Federal area. WFEC submitted an application on 

March 26, 2007, to incorporate these emissions limits into their current permit to be exempt from 

BART. This modification will not only incorporate the requested emissions limits but will also 

update all rules and regulations. 

SECTION II. FACILITY DESCRIPTION 

Western Farmers Electric Cooperative (WFEC) operates the Anadarko Power Plant to generate 

wholesale electricity which is transmitted over WFEC’s system. The electricity is sold in rural 

areas of approximately 3/4 of the state of Oklahoma. The facility consists of three natural gas 

fired high pressure boilers, three gas/oil fired combined cycle gas turbines, a fire pump diesel 

engine for emergency backup, and other insignificant and trivial sources. The three boilers are 

backup units that only operate when it is feasible, such as during peak demand. Two of the 

boilers that had been idle since 1984 were replaced in 1999. There are also two simple cycle 

turbines located on-site permitted under a separate Part 70 operating permit which was issued to 

WFEC Genco, LLC., Permit No. 2000-273-TV. 

The combined cycle units consists of three parallel lines of equipment. Each line includes a 

gas/oil fired turbine and a condensing-type steam turbine drive connected by tandem shafting to 

a single electrical generator. Exhaust gases from each turbine are used to heat separate waste 

heat steam generators (boilers). Exhaust gases from the steam generators then pass through 

separate stacks to the atmosphere. 

The gas/oil fired turbines produce power in the form of electrical energy and supply preheated 

combustion gases to the heat recovery boilers. Each turbine draws in compressed ambient air 

which is used to ignite the gas/oil in the combustion chamber and is expanded through the 

turbine driving the generator. The heat recovery boilers then use an extended-fin tube 

construction to recover heat from the large volumes of exhaust gases. The condensate leaving 

the condenser hotwell is pumped into the three stage fin tube surface boiler. 

There are three operating scenarios for the facility. For Scenario I, the boilers and turbines will 

be fueled with commercial-grade natural gas. For Scenario II, the turbines will be fueled with 

fuel oil and the boilers will be fueled with natural gas. For Scenario III, the proposed BART 

emission limits have been incorporated and the boilers and turbines will be fueled with 

commercial grade natural gas except during emergencies and testing for emergency preparedness 

when the turbines will be fired with very low sulfur fuel oil. Emission units (EUs) are arranged 

into Emission Unit Groups (EUGs) in the “Equipment” section. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 3 

SECTION III. EQUIPMENT 

EUG 1 Boilers

EU Manufacturer MMBTUH MW Serial # Const. Date 

AN-UNIT1R Nebraska 223 15 A-3882 1998 

AN-UNIT2R Nebraska 223 15 A-3648 1997 

EUG 2 Grandfathered Boiler

EU Manufacturer MMBTUH MW Serial # Const. Date 

AN-UNIT3 Riley Stoker 531 44 3333 1958 

EUG 3 Combined Cycle Gas Turbines

EU Manufacturer MMBTUH MW Serial # Const. Date 

AN-UNIT4 General Electric 852 100 248851 1975 

AN-UNIT5 General Electric 852 100 248852 1975 

AN-UNIT6 General Electric 852 100 248853 1975 

EUG 4 Internal Combustion Engine

EU Make/Model hp Serial # Const. Date 

AN-ENG1 Cummings NT-855-F 309 10531247 1975 

EUG 5 Tanks 

EU Point Contents Barrels Gallons Const. Date 

Tanks T-1 Fuel Oil No. 2 443 18,600 1951 

 T-3 Fuel Oil No. 2 109,524 4,600,000 1975 

 T-4 Fuel Oil No. 2 109,524 4,600,000 1975 

 T-5 Unleaded Gasoline (UST) 238 10,000 1977 

 T-6 Unleaded Gasoline (UST) 238 10,000 1977 

 T-7 Diesel Fuel (UST) 286 12,000 1977 

 T-8 Condensate 298 12,500 1975 

 T-10 Lube Oil 71 3,000 1975 

 T-11 Mineral Oil 71 3,000 1975 

 T-12 Mineral Oil 71 3,000 1975 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 4 

Stack Parameters 

EU 

Height 

(feet) 

Diameter 

(feet) 

Flow 

(ACFM) 

Temperature 

(°F) 

AN-UNIT1R 51 4.4 60,405 390 

AN-UNIT2R 51 4.4 60,405 390 

AN-UNIT3 111 7.5 107,928 260 

AN-UNIT4 80 14.9 872,590 325 

AN-UNIT5 80 14.9 872,590 325 

AN-UNIT6 80 14.9 872,590 325 

SECTION IV. EMISSIONS 

Potential emissions are listed in the emission tables and are based on continuous operation of 

EUs AN-UNIT3 through AN-UNIT6 and operation of EU AN-UNIT1R and AN-UNIT2R for a 

total of 5,800 hours. This leads to overestimating the emissions from the source due to the fact 

that the boilers are only operated during peak demand periods. Emissions from Scenario II are 

also overestimated due to the fact that fuel oil No. 2 is only used as an emergency backup fuel. 

For Scenario I, the boilers and combined cycle gas turbines are fired with natural gas. Potential 

emissions of NOX, CO, VOC, and PM10 from EUs AN-UNIT1R and AN-UNIT2R are based on 

manufacturer’s data for natural gas combustion (NOX: 0.035 lb/MMBTU, CO: 0.15 lb/MMBTU, 

VOC: 0.004 lb/MMBTU; PM10 0.005 lb/MMBTU) and each unit operating a maximum of 2,900 

hours per year. Potential emissions of SO2 are based on AP-42 (3/98), Section 1.3, Table 1.3-2 

and a maximum of 2,900 operating hours per year. The permit will allow operation of both units 

up to a combined total of 5,800 hours per year. Emission estimates for EU AN-UNIT3 fired 

with natural gas are based on continuous operation and AP-42 (2/98), Section 1.4, Tables 1.4-1 

and 1.4-2. Emission estimates of CO, VOC, PM10, and SO2 for the combined cycle gas turbines 

fired with natural gas are based on continuous operation and AP-42 (10/96), Section 3.1, Table 

3.1-1. Emission estimates of NOX for the combined cycle gas turbines fired with natural gas are 

based on stack testing conducted in September and October of 1998 (0.60 lb/MMBTU). The 

stack testing gave different emission rates of NOX for each unit. The maximum emission rate 

determined during the testing was used to predict the total potential emissions from the turbines. 

However, the individual emission factors will be used for emission inventory. Testing was not 

conducted at the maximum rating of the turbines but a linear relationship was shown between the 

heat input and emissions of NOX. Therefore, the maximum emission factor for NOX was 

extrapolated from the testing data. 

For Scenario II, the combined cycle gas turbines (EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6) 

are fired with fuel oil No. 2 continuously and the boilers (EUs AN-UNIT1R, AN-UNIT2R, and 

AN-UNIT3) are fired with natural gas. Emission estimates of CO, VOC, PM10, and SO2 for the 

combined cycle gas turbines fired with fuel oil No. 2 are based on continuous operation and AP42 (10/96), Section 3.1, Table 3.1-1. The NOX emissions from the combined cycle gas turbines 

are based on stack testing conducted at the facility in 1974 on EU AN-UNIT5. Since distillate 

fuel oil is only used for emergencies, these emission factors have been determined to be 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 5 

sufficient. The maximum fuel oil sulfur content and maximum fuel oil firing rate are based on a 

maximum SO2 emission rate for the combined cycle gas turbines. The fuel oil firing rate varies 

for each unit depending upon the fuel oil sulfur content and how many units are being fired with 

fuel oil. 

Allowable Fuel Oil Sulfur Concentration for different Operating Scenarios 

Fuel Oil 

% Sulfur 

Maximum 

Firing Rate 

When 3 

Units Are 

Operating 

(gal/hr/unit) 

Fuel Oil 

% Sulfur 

Maximum 

Firing Rate 

When 2 

Units Are 

Operating 

(gal/hr/unit) 

Fuel Oil 

% Sulfur 

Maximum 

Firing Rate 

For 1 Unit 

(gal/hr) 

0.340 1,000 

0.330 1,100 

0.320 1,200 

0.310 1,300 

0.185 1,000 0.300 1,400 

0.180 1,100 0.290 1,500 

0.140 1,000 0.175 1,200 0.280 1,600 

0.135 1,100 0.170 1,300 0.275 1,700 

0.130 1,200 0.165 1,400 0.270 1,800 

0.125 1,300 0.160 1,500 0.265 2,000 

0.120 1,500 0.155 1,600 0.260 2,100 

0.115 1,700 0.150 1,900 0.255 2,300 

0.110 2,000 0.145 2,200 0.250 2,700 

0.105 2,500 0.140 2,800 0.245 4,600 

0.100 5,000 0.135 4,600 0.240 4,800 

0.095 5,300 0.130 4,900 0.235 5,000 

0.090 5,700 0.125 5,200 0.230 5,200 

0.085 6,100 0.120 5,500 0.225 5,300 

0.080 6,500 0.115 5,700 0.220 5,400 

0.110 6,000 0.215 5,600 

0.105 6,500 0.210 5,700 

0.205 5,900 

0.200 6,100 

0.195 6,200 

0.190 6,500 

For Scenario III, the boilers and turbines are fired with commercial grade natural gas except 

during emergencies and testing for emergency preparedness when the turbines will be fired with 

very low sulfur fuel oil. Scenario III incorporates the proposed BART emission limits for the 

turbines. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 6 

The boilers, turbines, and engine have emissions of toxic air contaminants, the most significant 

being formaldehyde. Emissions of formaldehyde are based on the following: boilers - AP-42 

(7/98), Section 1.4; turbines - AP-42 (4/00), Section 3.1; and engine - AP-42 (10/96), Section 

3.3. Total formaldehyde emissions are below the major source levels. 

Formaldehyde Emissions from the Boilers, Turbines, and Engine 

 Factor Emissions 

Sources # Units MMBTUH lb/MMBTU lb/hr TPY 

Nebraska Boilers 2 223 0.0001 0.045 0.065 

Riley Stoker Boiler 1 528 0.0001 0.053 0.231 

GE Turbines 3 828 0.0007 1.739 7.616 

Cummings Engine 1 2.5 0.0012 0.003 0.001 

 

Totals 1.84 7.913 

Emission estimates for the 309-hp Cummings diesel fired engine are based on a maximum of 

500 operating hours per year and AP-42 (1/95), Section 3.3, Table 3.3-2, for uncontrolled diesel 

engines. Brake-specific fuel consumption for the 309-hp engine is 7,000 BTU/hp-hr for a fuel 

consumption of 15.5 gallons of diesel per hour. Because the engine will be limited to 500 hr per 

year, all emissions from the engine will be below 5 TPY. 

Facility-Wide Emissions Scenario I (Natural Gas)

 NOX CO VOC PM10 SO2

EU lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY 

AN-UNIT1R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT2R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT3 145.8 638.5 43.7 191.5 2.9 12.5 4.0 17.3 0.3 1.4

AN-UNIT4 580.01 2,239 93.7 410.5 20.5 89.6 35.7 156.4 0.6 2.4

AN-UNIT5 580.01 2,239 93.7 410.5 20.5 89.6 35.7 156.4 0.6 2.4

AN-UNIT6 580.01 2,239 93.7 410.5 20.5 89.6 35.7 156.4 0.6 2.4

AN-ENG1 9.6 2.4 2.1 0.5 0.8 0.2 0.7 0.2 0.6 0.2

Tanks --- --- --- --- 0.2 0.7 --- --- --- ---

 

TOTAL 1,911 7,381 393.9 1,521 67.2 284.8 114.0 489.9 2.9 9.2 1

 Based on the December 1999 stack test results. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 7 

Facility-Wide Emissions Scenario II (Fuel Oil No. 2)

 NOX CO VOC PM10 SO2

EU lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY 

AN-UNIT1R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT2R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT3 145.8 638.5 43.7 191.5 2.9 12.5 4.0 17.3 0.3 1.4

AN-UNIT4 630.5 2,762 40.90 179.1 14.5 63.4 52.0 227.6 74.4 326.0

AN-UNIT5 630.5 2,762 40.90 179.1 14.5 63.4 52.0 227.6 74.4 326.0

AN-UNIT6 630.5 2,762 40.90 179.1 14.5 63.4 52.0 227.6 74.4 326.0

AN-ENG1 9.6 2.4 2.1 0.5 0.8 0.2 0.7 0.2 0.6 0.2

Tanks --- --- --- --- 0.15 0.65 --- --- --- ---

 

TOTAL 2,063 8,950 235.5 826.3 49.2 206.2 162.9 703.5 224.3 980.0

Facility-Wide Emissions Scenario III (BART)

 NOX CO VOC PM10 SO2

EU lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY 

AN-UNIT1R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT2R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT3 145.8 638.5 43.7 191.5 2.9 12.5 4.0 17.3 0.3 1.4

AN-UNIT4 170.0 744.6 93.7 410.5 20.5 89.6 6.7 29.3 0.6 2.6

AN-UNIT5 170.0 744.6 93.7 410.5 20.5 89.6 6.7 29.3 0.6 2.6

AN-UNIT6 170.0 744.6 93.7 410.5 20.5 89.6 6.7 29.3 0.6 2.6

AN-ENG1 9.6 2.4 2.1 0.5 0.8 0.2 0.7 0.2 0.6 0.2

Tanks --- --- --- --- 0.2 0.7 --- --- --- ---

 

TOTAL 681.0 2,897 393.9 1,521 67.2 284.8 27.0 108.6 2.9 9.8

SECTION V. BART REVIEW 

To be an affected BART source, a source must meet the following criteria: 

3⁄4 the source must fall within the 26 source category list, 

3⁄4 have units which were put in place during the 1962 to 1977 time frame, 

3⁄4 and have potential emissions of air pollutants (NOX, SO2, PM10, PM2.5) which may 

reasonably cause or contribute to visibility impairment above 250 TPY from affected units. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 8 

The following units were determined to meet the time frame requirement. 

EUG 3 Combined Cycle Gas Turbines

EU Manufacturer MMBTUH MW Serial # Const. Date 

AN-UNIT4 General Electric 852 100 248851 1975 

AN-UNIT5 General Electric 852 100 248852 1975 

AN-UNIT6 General Electric 852 100 248853 1975 

EUG 4 Internal Combustion Engine

EU Make/Model hp Serial # Const. Date 

AN-ENG1 Cummings NT-855-F 309 10531247 1975 

Maximum Potential Emissions from Affected Emission Units 

 NOX PM10 SO2

EU lb/hr TPY lb/hr TPY lb/hr TPY 

AN-UNIT4 630.5 2,762 52.0 227.6 74.4 326.0 

AN-UNIT5 630.5 2,762 52.0 227.6 74.4 326.0 

AN-UNIT6 630.5 2,762 52.0 227.6 74.4 326.0 

AN-ENG1 9.6 2.4 0.7 0.2 0.6 0.2 

 

TOTAL 8,288 683.0 978.2 

Since the affected units have potential emissions above 250 TPY, the units are BART-eligible. 

Subchapter 8 requires WFEC to either do a BART control review or to submit modeling 

demonstrating the affected equipment does not cause or contribute to visibility impairment in 

any mandatory Class I Federal area. Any BART controls or limits taken to assure the affected 

equipment does not cause or contribute to visibility impairment must be installed and operating 

within five years of approval of the Regional Haze SIP. 

As previously indicated, WFEC has proposed to install control equipment and to limit emissions 

within five years of SIP approval to assure affected units do not cause or contribute to visibility 

impairment in any mandatory Class I Federal area. The following table details the new limits. 

Even though the turbines are capable of firing natural gas or fuel oil No. 2, the limits are 

applicable when burning either fuel. WFEC is proposing to either modify the units and/or install 

appropriate controls to meet the following limits. 

Proposed BART Emission Limits 

 NOX PM10 SO2

EU lb/hr TPY lb/hr TPY lb/hr TPY 

AN-UNIT4 170.0 744.6 6.7 29.3 0.6 2.6 

AN-UNIT5 170.0 744.6 6.7 29.3 0.6 2.6 

AN-UNIT6 170.0 744.6 6.7 29.3 0.6 2.6 

AN-ENG1 9.6 2.4 0.7 0.2 0.6 0.2 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 9 

WFEC conducted a modeling review to demonstrate that the affected units would not cause or 

contribute to visibility impairment in any mandatory Class I Federal area based on the newly 

proposed limits. Results of the modeling reviewed are provided in Section VI. Class I Area 

Modeling indicates that the affected sources would have a 0.461 deciview impact on the Wichita 

Mountains Class I area. Since this impact is below 0.5 deciview, the facility has demonstrated it 

will not cause or contribute to visibility impairment at the Wichita Mountains Class I area. 

Based on this impact and the distance and direction to other Class I areas, WFEC will have 

negligible impacts at other Class I areas. 

The permit has been modified to require compliance with the proposed limits within five years of 

the Oklahoma Regional Haze SIP approval. 

SECTION VI. CLASS I AREA MODELING 

Background

On July 1, 1999, the U.S. Environmental EPA published the final Regional Haze Rule (RHR). 

The objective of the RHR is to improve visibility in 156 specific areas across with United States, 

known as Class I areas. The Clean Air Act defines Class I areas as certain national parks (over 

6000 acres), wilderness areas (over 5000 acres), national memorial parks (over 5000 acres), and 

international parks that were in existence on August 7, 1977. 

On July 6, 2005, the EPA published amendments to its 1999 RHR, often called the BART rule, 

which included guidance for making source-specific Best Available Retrofit Technology 

(BART) determinations. The BART rule defines BART-eligible sources as sources that meet the 

following criteria: 

(1) Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant, 

(2) Began operation between August 7, 1962 and August 7, 1977, and 

(3) Are listed as one of the 26 listed source categories in the guidance. 

A BART-eligible source is not automatically subject to BART. Rather, BART-eligible sources 

are subject-to-BART if the sources are “reasonably anticipated to cause or contribute to visibility 

impairment in any federal mandatory Class I area.” EPA has determined that sources are 

reasonably anticipated to cause or contribute to visibility impairment if the visibility impacts 

from a source are greater than 0.5 deciviews (dv) when compared against a natural background. 

Air quality modeling is the tool that is used to determine a source’s visibility impacts. States 

have the authority to exempt certain BART-eligible sources from installing BART controls if the 

results of the dispersion modeling demonstrate that the source cannot reasonably be anticipated 

to cause or contribute to visibility impairment in a Class I area. Further, states also have the 

authority to define the modeling procedures for conducting modeling related to making BART 

determinations. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 10 

To promote consistency between states in the development of BART modeling protocols and to 

harmonize the approaches between adjacent RPO, the Central States Regional Air Planning 

(CENRAP) organization developed BART Modeling Guidelines (December 15, 2005). The 

intent of the guidelines is to assist CENRAP states and source operators in the development of 

statewide and source-specific modeling protocols. 

The following summarizes the modeling methods and procedures that were followed to conduct 

a refined CALPUFF modeling analysis for the WFEC Anadarko Power Plant. It was determined 

that the proposed emission limits would reduce the impact of the Anadarko Power Plant to a 

degree that the 98th percentile of the visibility impact predicted by the modeling due to all of the 

BART eligible sources at the station was below EPA’s recommended visibility contribution 

threshold of 0.5 Δdv. 

BART-Eligible Sources (Anadarko Power Plant)

EUG 3 Combined Cycle Gas Turbines

EU Manufacturer MMBTUH MW Serial # Const. Date 

AN-UNIT4 General Electric 852 100 248851 1975 

AN-UNIT5 General Electric 852 100 248852 1975 

AN-UNIT6 General Electric 852 100 248853 1975 

As required in CENRAP’s BART Modeling Guidelines, Class I areas within 300 km of the 

Anadarko Power Plant were included in the analysis. 

CALPUFF Modeling System

The main components of the CALPUFF modeling system are CALMET, CALPUFF, and 

CALPOST. CALMET is the meteorological model that generates hourly three-dimensional 

meteorological fields such as wind and temperature. CALPUFF simulates the non-steady state 

transport, dispersion, and chemical transformation of air pollutants emitted from a source in 

“puffs.” CALPUFF calculates hourly concentrations of visibility affecting pollutants at each 

specified receptor in a modeling domain. CALPOST is the post-processor for CALPUFF that 

computes visibility impacts from a source based on the visibility affecting pollutant 

concentrations that were output by CALPUFF. 

The versions of the CALPUFF modeling system programs that were used for conducting 

WFEC’s BART modeling are listed below. 

CALPUFF Modeling System Versions 

Processor Version Level 

TERREL 3.311 030709 

CTGCOMP 2.22 030528 

CTGPROC 2.42 030709 

MAKEGEO 2.22 030709 

CALMM5 2.4 050413 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 11 

CALPUFF Modeling System Versions (cont.) 

Processor Version Level 

CALMET 6.211 060414 

CALPUFF 6.112 060412 

POSTUTIL 1.4 040818 

CALPOST 6.131 060410 

Modeling Domain

The CALPUFF modeling system utilizes three modeling grids: the meteorological grid, the 

computational grid, and the sampling grid. The meteorological grid is the system of grid points 

at which meteorological fields are developed with CALMET. The computational grid 

determines the computational area for a CALPUFF run. Puffs are advected and tracked only 

while within the computational grid. The meteorological grid is defined so that it covers the 

areas of concern and gives enough marginal buffer area for puff transport and dispersion. The 

computational domain was set to extend at least 50 km in all directions beyond the Anadarko 

Power Plant and the Class I areas of interest. The map projection for the modeling domain was 

Lambert Conformal Conic (LCC) and the datum was the North American Datum 1927 (NAD27). The reference point for the modeling domain is Latitude 33.25°N, Longitude 100.5°W. The 

northeast corner was Latitude 37.25oN and Longitude 92oW. The meteorological grid spacing 

was 3 km. 

Vertical Layers 

Layer Cell Face 

Height (m) 

1 20 

2 40 

3 80 

4 160 

5 320 

6 640 

7 1,200 

8 2,000 

9 3,000 

10 4,000 

The height of the top vertical layer was set to 3,500 meters. This height corresponds to the top 

sounding pressure level for which upper air observation data will be relied upon. The vertical 

dimension of the domain was divided into 10 layers. The vertical dimensions were weighted 

towards the surface to resolve the mixing layer while using a somewhat coarser resolution for the 

layers aloft. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 12 

Geophysical Data

CALMET requires geophysical data to characterize the terrain and land use parameters that 

potentially affect dispersion. Terrain features affect flows and create turbulence in the 

atmosphere and are potentially subjected to higher concentrations of elevated puffs. Different 

land uses exhibit variable characteristics such as surface roughness, albedo, Bowen ratio, and 

leaf-area index that also effect turbulence and dispersion. 

Terrain Data

Terrain data was obtained from the United States Geological Survey (USGS) in 1-degree 

(1:250,000 scale or approximately 90 meter resolution) digital format. The USGS terrain data 

was then processed by the TERREL program to generate grid-cell elevation averages across the 

modeling domain. 

Land Use Data

USGS Composite Theme Grid (CTG) format Land Use and Land Cover (LULC) data files at 

1:250,000 resolution were used. Where 1:250,000 land use data was not available, USGS data at 

1:100,000 resolution was used. The USGS CTG format LULC data files were compressed prior 

to use in the CTGPROC utility processor using the CTGCOMP program. The LULC data were 

processed by the CTGPROC program to generate land use for each grid cell across the modeling 

domain. 

Compiling Terrain And Land Use Data

The terrain data files output by the TERELL program and the LULC files output by the 

CTGPROC program were then uploaded into the MAKEGEO program to create a geophysical 

data file that was used as the input for CALMET. 

CALMET

CALMET is the meteorological processor that compiles meteorological data from raw 

observations of surface and upper air conditions, precipitation measurements, mesoscale model 

output, and geophysical parameters into a single hourly, gridded data set for input into 

CALPUFF. CALMET was used to assimilate data for 2001-2003 using National Weather 

Service (NWS) surface station observations, precipitation data, and mesoscale model output to 

develop the meteorological fields. Upper air observations were not used in generating the 

meteorological fields. 

MM5 Data

Hourly mesoscale data was used as the initial guess field in developing the CALMET 

meteorological data. The following 5th generation mesoscale model meteorological data sets (or 

MM5 data) was used in the analysis: 

• 2001 MM5 data at 12 km resolution generated by the U.S. EPA 

• 2002 MM5 data at 36 km resolution generated by the Iowa DNR 

• 2003 MM5 data set at 36 km resolution generated by the Midwest RPO 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 13 

Surface Data

Parameters affecting turbulent dispersion that are observed hourly at surface stations include 

wind speed and direction, temperature, cloud cover and ceiling, relative humidity, and 

precipitation type. The stations were selected from the available data inventory to optimize 

spatial coverage and representation of the domain. Data from the stations was processed for use 

in CALMET using the SMERGE program. 

Missing surface data was filled using procedures recommended by EPA. Missing data periods of 

5 hours or less were replaced using these procedures. For periods greater than 5 hours, data was 

left either unfilled or was not used in CALMET processing. A large enough quantity of surface 

stations were included in the domain so that overlapping areas of influence would allow data 

from an alternate station to be used. 

The use of multiple stations for meteorological observations in CALMET/CALPUFF provides a 

substantial enhancement over the steady-state treatment of observations from a single 

meteorological station. Surface data were extracted from the surface stations. Raw observations 

from these stations were obtained from the National Climatic Data Center (NCDC). The data 

was quality assured and then merged using the SMERGE pre-processor to create a single 

assimilated data file of surface observations for each year analyzed. 

Precipitation Data

The effects of chemical transformation and deposition processes on ambient pollutant 

concentrations will be considered in this analysis. Therefore, it was necessary to include 

observations of precipitation in the CALMET analysis. The stations were selected from the 

available data inventory to optimize spatial coverage and representation of the domain. Data 

from the stations will be processed for use in CALMET using the PMERGE program. 

Upper Air Data

Upper Air observations were not used in the CALMET analysis (i.e. NOOBS=1). 

CALMET Control Parameters

The modeling was conducted using the CENRAP recommended parameters, except the ones 

listed below. A explanation is also provided as to why the CENRAP recommended parameters 

were not used for these variables. Most of the differences are due to the inclusion of observation 

data into the modeling analysis. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 14 

CALMET Input Variables Where CENRAP Suggested Value was not Used 

Variable Suggested Used Description Reason 

DGRIDKM 6.0 3.0 Grid spacing (km) Refined grid spacing 

NN2 1 2 Last time step for debug data to be 

printed 

Generated debug data for 

2 time steps 

NZPRN2 0 1 # Of levels at surface to print Default 

NOOBS 2 1 No obs mode Used surface OBS 

NSSTA 0 47 # Met stations in surf.dat # of stations 

NPSTA 0 135 # Met stations in precip.dat # of stations 

ICLOUD 3 0 Gridded Cloud Fields Default 

IFORMC 2 1 Format cloud data N/A - no cloud data used 

IKINE 0 1 Adjust winds using kinematic 

effects 

Computed kinematic 

effects 

RMAX1 30 100 Max radius of influence over land 

in surface layer (km) IWAQM Phase 2 Study 

RMAX2 30 500 Max radius of influence over land 

aloft (km) IWAQM Phase 2 Study 

RMAX3 30 36 Max radius of influence over 

water (km) Used MM5 data spacing 

R1 1 50 Weighting of 1st guess surface 

field (km) IWAQM Phase 2 Study 

R2 1 100 Weighting of 1st guess aloft field 

(km) IWAQM Phase 2 Study 

ITPROG 2 1 3D temp from observations or 

MM5 

Used surface 

observations 

CALPUFF

The CALPUFF model uses the output file from CALMET together with source, receptor, and 

chemical reaction information to predict hourly concentration impacts. 

Source Emissions

WFEC proposes reduced NOX emission limitations for the three combustion turbines that 

constitute the BART-eligible sources at the Anadarko Plant. A summary of potential emissions 

from the three turbines is summarized below. NOX emissions are based on manufacturersupplied estimates. SO2 emissions are based on the turbines' maximum heat duty and emission 

factors obtained from AP-42 (4/00), Section 3.1 for natural gas fired turbines for natural gas with 

a maximum sulfur content of 6.2 ppmv sulfur (6.2E-4%). PM10 emissions are based on the 

turbines' maximum heat duty and emission factors obtained from AP-42 (4/00), Section 3.1 for 

natural gas fired turbines. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 15 

Post Project PTE

 NOX PM10 SO2

EU lb/hr TPY lb/hr TPY lb/hr TPY 

AN-UNIT3 170.0 744.6 6.7 29.3 0.6 2.6 

AN-UNIT4 170.0 744.6 6.7 29.3 0.6 2.6 

AN-UNIT5 170.0 744.6 6.7 29.3 0.6 2.6 

PM10 Speciation

Total PM10 emissions are not directly entered into the CALPUFF model but are instead input as 

coarse and fine constituents. The PM10 emissions from the turbines are speciated according to 

the Federal Land Managers' (FLM) guidance to include the following: 

3⁄4 Coarse particulate matter (PMC, considered PM2.5-10) 

3⁄4 Fine particulate matter (PMF, considered PM<2.5) 

3⁄4 Sulfates (SO4) 

3⁄4 Secondary organic aerosols (SOA) 

3⁄4 Elemental carbon (EC) 

Based upon FLM guidance, PM10 emissions from natural gas combustion consist of coarse, 

fine, elemental carbon (EC), and secondary organic aerosol (SOA) components. The 

breakdown of these components is shown below. 

PM SPECIATION PROFILE 

Particulate Matter Species Fraction 

PM Coarse (Soil) 25% 

Elemental Carbon (EC) 0% 

PM Fine 75% 

Secondary Organic Aerosols 0% 

(organic carbon) 

Total 100% 

SO4 emissions are primarily the result of sulfuric acid formed from conversion of SO2 to SO3

and are based on 5% conversion of SO2 to SO3 and 100% conversion of SO3 to H2SO4. A 

summary of particulate emissions from the turbines is summarized below. 

SPECIATED PM10 EMISSIONS 

 Emissions 

Pollutant (lb/hr) 

SO4 0.045 

PM (coarse) 5.024 

PM (fine) 1.675 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 16 

Reduction of NOX emissions at the turbines may result in changes to the exhaust profile of the 

turbines. Although the physical dimensions of the stack will remain unchanged, the exhaust flow 

and temperature may vary. A summary of the stack parameters utilized in conducting the 

modeling were based on manufacturer data and are shown below. 

Stack Parameters 

Emission Latitude Longitude Exhaust Stack Stack Exit Exit 

Unit degrees degrees Flow Height Diameter Velocity Temp.

 NAD27 NAD27 ACFM feet feet ft/s °F 

AN-UNIT4 35.0826 98.2249 873,000 80 13.5 101 325 

AN-UNIT5 35.0821 98.2243 873,000 80 13.5 101 325 

AN-UNIT6 35.0826 98.2243 873,000 80 13.5 101 325 

Base elevation of each of the units is 360 meters (1,180 feet) above MSL based upon visual 

inspection of USGS topographic maps. 

Receptor Locations

The National Park Service (NPS) provides electronic files that include the discrete locations and 

elevations of receptors to be evaluated in Class I area analyses. The receptor files were 

downloaded from the NPS website, converted into the LCC NAD27 projection, and incorporated 

into the CALPUFF model. 

Background Ozone

Background ozone concentrations were required in order to model the photochemical conversion 

of SO2 and NOX to sulfates (SO4) and nitrates (NO3). CALPUFF can use either a single 

background value representative of an area or hourly ozone data from one or more ozone 

monitoring stations. CENRAP recommended either developing background ozone 

concentrations from ambient monitors located within the domain being modeled or from the 

most recent CENRAP CMAQ/CAMX simulation for the 2002 base year. Modeling was 

conducted using a conservative background concentration of 40 ppb. This is the default 

background concentration from the CENRAP protocol. 

Background Ammonia

Background concentrations of ammonia were required to model the formation of ammonia 

nitrates and sulfates. CENRAP recommended developing background concentrations from the 

most recent CENRAP CMAQ or CAMX simulation for the 2002 base year. Since the 

CMAQ/CAMX modeled and observed monthly averaged concentrations exhibit wide spatial 

variability and the data is not readily available, a conservative background concentration of 3 

ppb was used. This is the default background concentration from the CENRAP protocol. 

CALPUFF Model Control Parameters

The modeling was conducted using the CENRAP recommended parameters, except the ones 

listed below. A explanation is also provided as to why the CENRAP recommended parameters 

were not used for these variables. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 17 

CALPUFF Input Variables Where CENRAP Suggested Value was not Used 

Variable Suggested Used Description Reason 

NSE 8 6 # Chemical Species to 

be emitted 

SOA and EC not 

included 

MSPLIT 0 1 

Puff splitting 

Allowed for puff 

splitting due to 

distances 

DGRIDKM 6.0 3.0 Grid Spacing (km) Refined Grid Spacing 

MOZ 1 0 Read Background 

Ozone Concentrations Default 

MH2O2 1 0 Background H2O2 

Concentrations 

Need to chose 0 to use 

monthly background 

value 

BCKH2O2 1 12*1 Background Monthly 

H2O2 Concentrations Default 

OFRAC 0.2 0.15, 0.15, 0.2, 0.2, 

0.2, 0.2, 0.2, 0.2, 

0.2, 0.2, 0.2, 0.15 

Organic Fraction for 

SOA option 

Irrelevant 

MCHEM ≠ 4 

IPTU 1 3 Units for Point Source 

emissions Used lb/hr 

CALPOST

A three-year CALPOST analysis was conducted to determine the visibility change in deciview 

(dv) caused by WFEC’s BART-eligible sources when compared to a natural background. 

Light Extinction Algorithm

EPA's currently approved algorithm for reconstructing light extinction (as opposed to the new 

equation for reconstructing light extinction recommended by the IMPROVE Steering 

Committee) was used. The background extinction coefficient bext, background is affected by 

various chemical species and the Rayleigh scattering phenomenon. The light extinction equation 

is provided below. 

bext = 3*f(RH)*[(NH4)2SO4] + 3*f(RH)*[NH4NO3] + 4*[OC] + l*[PMF] + 0.6*[PMC] + 10*[EC] + bRay

The algorithm was used to calculate the daily light extinction attributable to the Seminole 

Station's BART eligible sources and light extinction attributable to a natural background. The 

change in deciviews based on the source and background light extinctions was evaluated using 

the equation below. 

∆ dv = 1 0 *ln[(bext, background + bext, source)/bext, background] 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 18 

CALPOST Processing Method

CALPOST Method 6, which calculates hourly light extinction impacts for the source and 

background using monthly average relative humidity adjustment factors was used in the refined 

BART analysis. Monthly Class I area-specific relative humidity adjustment factors based on the 

centroid of the Class I areas as included in Table A-3 of EPA’s Guidance for Estimating Natural 

Visibility Conditions Under the Regional Haze Program were used. 

Monthly Humidity Factors 

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Wichita Mountains 2.7 2.6 2.4 2.4 3.0 2.7 2.3 2.5 2.9 2.6 2.7 2.8 

Natural Background

EPA’s default average annual aerosol concentrations for the U.S. that are included in Table 2-1 

of EPA’s Guidance for Estimating Natural Visibility Conditions Under the Regional Haze 

Program were used.

Default Average Annual Natural Background Levels 

Class I Area Region SO4 NO3 OC EC Soil Coarse Mass 

Wichita Mountains WEST 0.12 0.10 0.47 0.02 0.50 3.00 

Evaluating Visibility Results

Trinity compared the high of the 2001 through 2003 daily ∆ dv values output by CALPOST to a 

contribution threshold of 0.5 ∆ dv. If the 98th percentile ∆ dv values (the 7th highest value, 22nd 

highest over three years) output by CALPOST is less 0.5 ∆ dv, then the source is exempt from 

BART requirements. 

Summary of CALPOST Control Parameters

A listing of the CALPOST parameters that Trinity used in OG&E's modeling analysis. In cases 

where a parameter to be used is different than what CENRAP recommended, a short explanation 

as to the difference is provided. 

A summary of the top 25 visibility-impairing days at each of the relevant Class I areas over the 

modeled 2001-03 period is summarized below. Shaded values indicate visibility impacts that 

exceed the 0.5 ∆dv threshold for contribution to visibility impairment. As shown in the table, the 

98th percentile values indicate that the Anadarko Power Plant's contribution to visibility 

impairment is below the 0.5 ∆dv threshold. These results indicate that the Anadarko Power Plant 

therefore qualifies for a waiver from BART. 

CALPOST Input Variables Where CENRAP Suggested Value was not Used 

Variable Suggested Used Description Reason 

BEXTBTBK 12 NA Background Extinction for 

MVISBK=1 

Not necessary since 

MVISBK=6 

RHFRAC 10 NA % of Particles affected by RH Not necessary since 

MVISBK=6 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 19 

Visibility Impact Modeling Results for Wichita Mountains 2001-2003 

Rank Modeled 

Visibility 

Impact (∆dv) 

Background Extinction by Species (%) Year Day 

SO4 NO3 OC EC PMC PMF 

2001 

1 0.392 0.05 92.44 0 0 1.05 6.45 2001 66 

2 0.364 0.15 94.04 0 0 0.85 4.96 2001 128 

3 0.340 0.06 97.51 0 0 0.36 2.07 2001 15 

4 0.338 0.17 98.24 0 0 0.23 1.36 2001 88 

5 0.304 0.15 93.81 0 0 0.91 5.13 2001 261 

6 0.302 0.26 95.42 0 0 0.67 3.66 2001 308 

7 0.289 0.09 93.68 0 0 0.94 5.28 2001 127 

8 0.260 0.06 93.98 0 0 0.88 5.09 2001 267 

9 0.248 0.16 96.34 0 0 0.51 2.99 2001 364 

10 0.225 0.05 97.57 0 0 0.29 2.09 2001 361 

2002 

1 0.607 0.21 96.74 0 0 0.44 2.61 2002 148 

2 0.491 0.08 94.63 0 0 0.79 4.5 2002 290 

3 0.451 0.16 98.84 0 0 0.15 0.86 2002 37 

4 0.444 0.05 95.94 0 0 0.61 3.41 2002 66 

5 0.431 0.04 94 0 0 0.82 5.14 2002 17 

6 0.406 0.24 96.84 0 0 0.42 2.5 2002 282 

7 0.277 0.19 95.4 0 0 0.62 3.8 2002 305 

8 0.255 0.04 94.2 0 0 0.88 4.87 2002 51 

9 0.248 0.08 98.41 0 0 0.2 1.32 2002 1 

10 0.243 0.19 96.93 0 0 0.42 2.46 2002 301 

2003 

1 0.515 0.05 98.71 0 0 0.17 1.07 2003 320 

2 0.480 0.05 97.07 0 0 0.39 2.49 2003 89 

3 0.459 0.08 96.08 0 0 0.54 3.3 2003 69 

4 0.410 0.04 96.89 0 0 0.46 2.6 2003 317 

5 0.361 0.18 97.19 0 0 0.39 2.25 2003 57 

6 0.325 0.04 93.62 0 0 0.95 5.38 2003 116 

7 0.302 0.16 94.3 0 0 0.79 4.75 2003 277 

8 0.282 0.06 96.27 0 0 0.49 3.18 2003 42 

9 0.269 0.24 94.84 0 0 0.72 4.21 2003 305 

10 0.266 0.06 94.09 0 0 0.87 4.98 2003 51 

SECTION VII. INSIGNIFICANT ACTIVITIES 

The insignificant activities identified and justified in the application are duplicated below. 

Appropriate recordkeeping of activities indicated below with “*” is specified in the Specific 

Conditions. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 20 

1. Space heaters, boilers, process heaters, and emergency flares less than or equal to 5 

MMBTU/hr heat input (commercial natural gas). There are three small portable space 

heaters located on-site and which are rated at 1 MMBTU/hr and others may be used in the 

future. 

2. Emissions from stationary internal combustion engines rated less than 50 hp output. 

Currently, there are no stationary internal combustion engines rated less than 50 hp located 

at the facility but they may be used in the future. 

3. * Emissions from fuel storage/dispensing equipment operated solely for facility owned 

vehicles if fuel throughput is not more than 2,175 gallons/day, averaged over a 30-day 

period. Tanks T-5 and T-6 are used to store and dispense unleaded gasoline and have an 

average throughput of 110 gallons/day. Tank T-7 is used to store and dispense diesel fuel 

and has an average monthly throughput of 60 gallons/day. 

4. Emissions from crude oil or condensate marine and truck loading equipment operations at 

crude oil and natural gas production sites where the loading rate does not exceed 10,000 

gallons per day averaged over a 30-day period. Unloading of tank T-8 into tank trucks is 

less than 10,000 gallons per day. Tank T-8 stores condensate but has not had any 

throughput in recent years. 

5. * Emissions from crude oil and condensate storage tanks with a capacity of less than or 

equal to 420,000 gallons that store crude oil and condensate prior to custody transfer. Tank 

T-8 stores condensate prior to custody transfer and has a capacity of 12,500 gallons. 

6. * Emissions from storage tanks constructed with a capacity less than 39,894 gallons which 

store VOC with a vapor pressure less than 1.5 psia at maximum storage temperature. 

Tanks T-1 and T-7 have capacities less than 39,894 gallons and store products having a 

vapor pressure less than 1.5 psia. 

7. Cold degreasing operations utilizing solvents that are denser than air. Three parts washers 

are located at the facility which use approximately 42 gallons/month of a solvent that is 

denser than air. 

8. Surface coating operations that do not exceed a combined total usage of more than 60 

gallons/month of coatings, thinners, and clean-up solvents at any one emission unit. 

Surface coating is conducted at the facility as part of routine maintenance. 

9. Exhaust systems for chemical, paint, and/or solvent storage rooms or cabinets, including 

hazardous waste satellite (accumulation) areas. There are four storage rooms/cabinets used 

for storing chemicals, paints, and solvents and others may be used in the future. 

10. Hand wiping and spraying of solvents from containers with less than 1 liter capacity used 

for spot cleaning and/or degreasing in ozone attainment areas. Small amounts of solvent 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 21 

used for degreasing are applied to facility components using a rag and emissions are 

included in No. 8. 

11. * Activities that have the potential to emit no more than 5 TPY (actual) of any criteria 

pollutant. The facility has not identified any other activities that have the potential to emit 

more than 5 TPY (actual) of any criteria pollutant but it may have some in the future. 

SECTION VIII. OKLAHOMA AIR POLLUTION CONTROL RULES 

OAC 252:100-1 (General Provisions) [Applicable] 

Subchapter 1 includes definitions but there are no regulatory requirements. 

OAC 252:100-2 (Incorporation by Reference) [Applicable] 

This subchapter incorporates by reference applicable provisions of Title 40 of the Code of 

Federal Regulations. These requirements are addressed in the “Federal Regulations” section. 

OAC 252:100-3 (Air Quality Standards and Increments) [Applicable] 

Primary Standards are in Appendix E and Secondary Standards are in Appendix F of the Air 

Pollution Control Rules. At this time, all of Oklahoma is in attainment of these standards. 

OAC 252:100-5 (Registration, Emission Inventory, and Annual Operating Fees) [Applicable] 

Subchapter 5 requires sources of air contaminants to register with Air Quality, file emission 

inventories annually, and pay annual operating fees based upon total annual emissions of 

regulated pollutants. Emission inventories have been submitted and fees paid for the past years. 

OAC 252:100-8 (Permits for Part 70 Sources) [Applicable] 

Part 5 includes the general administrative requirements for part 70 permits. Any planned 

changes in the operation of the facility which result in emissions not authorized in the permit and 

which exceed the “Insignificant Activities” or “Trivial Activities” thresholds require prior 

notification to AQD and may require a permit modification. Insignificant activities mean 

individual emission units that either are on the list in Appendix I (OAC 252:100) or whose actual 

calendar year emissions do not exceed the following limits: 

• 5 TPY of any one criteria pollutant 

• 2 TPY of any one hazardous air pollutant (HAP) or 5 TPY of multiple HAP or 20% 

of any threshold less than 10 TPY for a HAP that the EPA may establish by rule 

Emission limits for the facility are based on Permit No. 2005-037-TVR and the proposed BART 

emission limitations. 

OAC 252:100-9 (Excess Emissions Reporting Requirements) [Applicable] 

Except as provided in OAC 252:100-9-7(a)(1), the owner or operator of a source of excess 

emissions shall notify the Director as soon as possible but no later than 4:30 p.m. the following 

working day of the first occurrence of excess emissions in each excess emission event. No later 

than thirty (30) calendar days after the start of any excess emission event, the owner or operator 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 22 

of an air contaminant source from which excess emissions have occurred shall submit a report 

for each excess emission event describing the extent of the event and the actions taken by the 

owner or operator of the facility in response to this event. Request for affirmative defense, as 

described in OAC 252:100-9-8, shall be included in the excess emission event report. Additional 

reporting may be required in the case of ongoing emission events and in the case of excess 

emissions reporting required by 40 CFR Parts 60, 61, or 63. 

OAC 252:100-13 (Open Burning) [Applicable] 

Open burning of refuse and other combustible material is prohibited except as authorized in the 

specific examples and under the conditions listed in this subchapter. 

OAC 252:100-19 (Particulate Matter) [Applicable] 

This subchapter specifies a particulate matter (PM) emission limitation of 0.6 lb/MMBTU from 

existing fuel-burning equipment with a rated heat input of 10 MMBTUH or less. For fuelburning equipment greater than 10 MMBTUH, this subchapter specifies a PM emission 

limitation based upon the heat input of the equipment. The two new boilers (AN-UNIT1 and 

AN-UNIT2) are rated at 233 MMBTUH and are subject to a PM emission limitation of 

approximately 0.28 lb/MMBTU. The old boiler (AN-UNIT3) is rated at 531 MMBTUH and is 

subject to a PM emission limitation of approximately 0.23 lb/MMBTU. The three combined 

cycle gas turbines (AN-UNIT4, AN-UNIT5, and AN-UNIT6) are rated at 828 MMBTUH and 

are subject to a PM emission limitation of approximately 0.21 lb/MMBTU. AP-42 (7/98), Table 

1.4-2, lists the total PM emissions from natural gas combustion to be 7.6 lb/MMft3

 or about 

0.0076 lb/MMBTU. AP-42 (10/96), Section 1.3, lists the total PM emissions for industrial 

boilers burning fuel oil No. 2 to be 3.3 lb/1,000 gallons or about 0.024 lb/MMBTU. AP-42 

(1/95), Table 3.1-2, lists the total PM emissions for large uncontrolled gas turbines burning 

natural gas to be 0.041 lb/MMBTU and large uncontrolled gas turbines burning fuel oil No. 2 to 

be 0.061 lb/MMBTU. All of these emission factors are in compliance with this subchapter. The 

permit will require the use of natural gas or distillate fuel (fuel oil No. 2) for all fuel-burning 

equipment to ensure compliance with Subchapter 19. 

OAC 252:100-25 (Visible Emissions and Particulate Matter) [Applicable] 

No discharge of greater than 20% opacity is allowed except for short-term occurrences which 

consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed 

three such periods in any consecutive 24 hours. In no case shall the average of any six-minute 

period exceed 60% opacity. When burning natural gas there is little possibility of exceeding the 

opacity standards. When burning fuel oil in the turbines, the permit requires visible emission 

observations. 

OAC 252:100-29 (Fugitive Dust) [Applicable] 

No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the 

property line on which the emissions originate in such a manner as to damage or to interfere with 

the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the 

maintenance of air quality standards. Under normal operating conditions, this facility will not 

cause a problem in this area, therefore it is not necessary to require specific precautions to be 

taken. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 23 

OAC 252:100-31 (Sulfur Compounds) [Applicable] 

Part 2 limits the impact of sulfur dioxide emissions from existing equipment. Modeling 

conducted using ISCST3 was used to show the impacts of the facility on the ambient air as 

shown below. EU AN-UNIT3 will always be fired with natural gas. 

Ambient Impacts of SO2

Standard Fuel Oil Natural Gas 

Averaging Time μg/m3 μg/m3 μg/m3

1-hour 1,200 471 3.34 

3-hour 650 363 2.71 

24-hour 130 130 1.49 

Annual 80 15 0.27 

Part 5 affects new fuel-burning equipment that was constructed after July 1, 1972. EU ANUNIT3 was constructed in 1958 and is applicable to the existing equipment emission limits. 

Fuel-burning equipment was defined as “any equipment, device, or contrivance, and all 

appurtenances thereto, including ducts, breeches, fuel-feeding equipment, ash-removal 

equipment, combustion controls, stacks, and chimneys, used primarily to burn any fuel for the 

purpose of indirect heating in which the material being heated is not contacted by and adds no 

substance to the products of combustion” prior to July 1, 1977. EUs AN-UNIT4 through ANUNIT6, the combined cycle gas turbines, were constructed in 1975. Therefore, they are existing 

equipment and are applicable to the existing equipment standards. However, the two new boilers 

(AN-UNIT1R and AN-UNIT2R) are subject to the new equipment standard which limits sulfur 

dioxide emissions from gaseous fuels to 0.2 lb/MMBTU heat input, based on a three-hour 

average. This is equivalent to approximately 1,203 ppmv sulfur. AP-42 (7/98), Table 1.4-2, lists 

the total SO2 emissions for natural gas to be 0.6 lb/MMft3 or about 0.0006 lb/MMBTU which is 

in compliance with Subchapter 31. The permit will require the use of commercial natural gas for 

EUs AN-UNIT1R and AN-UNIT2R to ensure compliance with Subchapter 31. 

OAC 252:100-33 (Nitrogen Oxides) [Applicable] 

NOX emissions are limited to 0.20 lb/MMBTU, three-hour average, from all new gas-fired fuelburning equipment with a rated heat input of 50 MMBTUH or greater. The old boiler (ANUNIT3) was constructed prior to the effective date of this regulation (February 14, 1972) and is 

not subject to these requirements. The combined cycle gas turbines were not affected units 

because they did not meet the definition of fuel-burning equipment in effect during construction. 

The two new boilers (AN-UNIT1R and AN-UNIT2R) are subject to this requirement. 

Manufacturers’ data based on stack testing estimates emissions of NOX from the new boilers at 

0.035 lb/MMBTU, which is in compliance with this subchapter. The new boilers are also subject 

to the NSPS, Subpart Db, NOX emission limit of 0.2 lb/MMBTU, which is as stringent. 

OAC 252:100-37 (Volatile Organic Compounds) [Applicable] 

Part 3 requires storage tanks constructed after December 28, 1974, with a capacity of 400 gallons 

or more and storing a VOC with a vapor pressure greater than 1.5 psia to be equipped with a 

permanent submerged fill pipe or with an organic vapor recovery system. The condensate and 

gasoline tanks are subject to this requirement. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 24 

Part 3 requires VOC loading facilities with a throughput equal to or less than 40,000 gallons per 

day to be equipped with a system for submerged filling of tank trucks or trailers if the capacity of 

the vehicle is greater than 200 gallons. This facility does not have the physical equipment (loading 

arm and pump) to conduct this type of loading and is not subject to this requirement. 

Part 5 limits the VOC content of coatings from any coating line or other coating operation. This 

facility does not normally conduct coating or painting operations except for routine maintenance 

of the facility and equipment, which is exempt. 

Part 7 requires fuel-burning and refuse-burning equipment to be operated and maintained so as to 

minimize VOC emissions. Temperature and available air must be sufficient to provide 

essentially complete combustion. 

Part 7 requires all effluent water separators openings or floating roofs to be sealed or equipped 

with an organic vapor recovery system. There are no effluent water separators located at this 

facility. 

OAC 252:100-42 (Toxic Air Contaminants (TAC)) [Applicable] 

This subchapter regulates toxic air contaminants (TAC) that are emitted into the ambient air in 

areas of concern (AOC). Any work practice, material substitution, or control equipment required 

by the Department prior to June 11, 2004, to control a TAC, shall be retained, unless a 

modification is approved by the Director. Since no AOC has been designated there are no 

specific requirements for this facility at this time. 

OAC 252:100-43 (Testing, Monitoring, and Recordkeeping) [Applicable] 

This subchapter provides general requirements for testing, monitoring and recordkeeping and 

applies to any testing, monitoring or recordkeeping activity conducted at any stationary source. 

To determine compliance with emissions limitations or standards, the Air Quality Director may 

require the owner or operator of any source in the state of Oklahoma to install, maintain and 

operate monitoring equipment or to conduct tests, including stack tests, of the air contaminant 

source. All required testing must be conducted by methods approved by the Air Quality Director 

and under the direction of qualified personnel. A notice-of-intent to test and a testing protocol 

shall be submitted to Air Quality at least 30 days prior to any EPA Reference Method stack tests. 

Emissions and other data required to demonstrate compliance with any federal or state emission 

limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained, 

and submitted as required by this subchapter, an applicable rule, or permit requirement. Data 

from any required testing or monitoring not conducted in accordance with the provisions of this 

subchapter shall be considered invalid. Nothing shall preclude the use, including the exclusive 

use, of any credible evidence or information relevant to whether a source would have been in 

compliance with applicable requirements if the appropriate performance or compliance test or 

procedure had been performed. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 25 

The following Oklahoma Air Pollution Control Rules are not applicable to this facility: 

OAC 252:100-11 Alternative Emissions Reduction not requested 

OAC 252:100-15 Mobile Sources not in source category 

OAC 252:100-17 Incinerators not type of emission unit 

OAC 252:100-23 Cotton Gins not type of emission unit 

OAC 252:100-24 Grain Elevators not in source category 

OAC 252:100-35 Carbon Dioxide not type of emission unit 

OAC 252:100-39 Nonattainment Areas not in area category 

OAC 252:100-47 Municipal Solid Waste Landfills not in area category 

SECTION IX. FEDERAL REGULATIONS 

Protection of Visibility, 40 CFR 51 Subpart P [Applicable] 

The primary purposes of this subpart are to require States to develop programs to assure 

reasonable progress toward meeting the national goal of preventing any future, and remedying 

any existing, impairment of visibility in mandatory Class I Federal areas which impairment 

results from manmade air pollution; and to establish necessary additional procedures for new 

source permit applicants, States and Federal Land Managers to use in conducting the visibility 

impact analysis required for new sources under §51.166. This subpart sets forth requirements 

addressing visibility impairment in its two principal forms: “reasonably attributable” impairment 

(i.e., impairment attributable to a single source/small group of sources) and regional haze (i.e., 

widespread haze from a multitude of sources which impairs visibility in every direction over a 

large area). Regional haze visibility impairment is partially addressed through the Best Available 

Retrofit Technology (BART) process. The facility has been determined to be subject to a BART 

review. 

Best Available Retrofit Technology (BART) requirements for regional haze visibility impairment. 

WFEC must either submit a BART review or a demonstration that the BART-eligible sources do 

not cause or contribute to any impairment of visibility in any mandatory Class I Federal area. As 

indicated in Section V, WFEC proposed to modify the affected units and take enforceable limits, 

such that, they would not cause or contribute to any impairment of visibility in any mandatory 

Class I Federal area. Requirements to comply within 5 years of SIP approval have been added to 

the permit. 

PSD, 40 CFR Part 52 [Applicable] 

Emissions of several regulated pollutants exceed 100 TPY, the level at which PSD defines the 

facility to be a major source. Any future expansion must be evaluated in the context of PSD 

significance levels (100 TPY CO, 40 TPY NOX, 40 TPY SO2, 40 TPY VOC, 25 TPY PM, 15 

TPY PM10, or 0.6 TPY lead). The permit will require the facility to apply for and obtain a PSD 

construction permit prior to modification of the turbines if the modifications will result in a 

significant emission increase and a significant net emission increase of a regulated NSR 

pollutant. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 26 

NSPS, 40 CFR Part 60 [Subpart Db is Applicable] 

Subpart D, Da, Electric Utility Steam Generating Units. All of the boilers are below the de 

minimis level of 250 MMBTUH for these subparts and EU AN-UNIT3 was constructed prior to 

the August 17, 1971, and September 18, 1978, applicability dates of these subparts. 

Subpart Db, Industrial-Commercial-Institutional Steam Generating Units. This subpart affects 

steam generating units with a heat input capacity greater than 100 MMBTUH and that 

commences construction, modification, or reconstruction after June 19, 1984. The two new 

boilers (EUs AN-UNIT1R, AN-UNIT2R) will have a heat input of 223 MMBTUH and are 

applicable to this subpart. EU AN-UNIT1R and AN-UNIT2R will only be permitted to combust 

natural gas and are subject to the NOX emission standard of § 60.44b(a)(1)(ii) (0.2 lb/MMBTU) 

and all applicable requirements. EU AN-UNIT3 was constructed prior to the June 19, 1984, 

applicability date of this subpart. 

The facility has requested use of a predictive emission monitoring system (PEMS) as allowed by 

§ 60.48b(g)(2) instead of a continuous emission monitoring system for the two new boilers. The 

PEMS has been approved and all monitoring and recordkeeping requirements for the PEMS will 

be included in the permit. 

Subpart Dc, Small Industrial-Commercial-Institutional Steam Generating Units. This subpart 

affects steam generating units with a heat input capacity between 10 and 100 MMBTUH and that 

commences construction, modification, or reconstruction after June 9, 1989. All emission units 

are above the threshold level of 100 MMBTUH. 

Subpart K, Ka, Kb, VOL Storage Vessels. Subpart Kb regulates hydrocarbon storage tanks 

larger than 19,813 gallons capacity and built after July 23, 1984. The condensate storage tanks 

at this facility are below this threshold; therefore, this subpart is not applicable. The 10,000 

gallon gasoline tanks are not subject because the were constructed prior to the effective date of 

Subpart Kb and are below the de minimis amount of 40,000 gallons for Subparts K, and Ka. The 

other large tanks are not subject because they store fuel oil No. 2 which has a vapor pressure of 

less than 1.5 psia. 

Subpart GG, Stationary Gas Turbines. This subpart affects stationary gas turbines with a heat 

input at peak load of greater than or equal to 10.7 gigajoules per hour (10 MMBTUH) based on 

the lower heating value (LHV) of the fuel and that commenced construction, reconstruction, or 

modification after October 3, 1977. The combined cycle gas turbines are not subject because 

they were constructed prior to the effective date and have not been modified or reconstruction as 

defined in NSPS, Subpart A. 

Subpart IIII, Stationary Compression Ignition (CI) Internal Combustion Engines (ICE). This 

subpart affects CI ICE manufactured after 2007. There are no CI ICE manufactured after 2007 

at this facility. 

Subpart JJJJ, Stationary Spark Ignition Internal Combustion Engines (SI ICE). This subpart 

affects SI ICE ordered after June 12, 2006 and all SI ICE engines modified or reconstructed after 

June 12, 2006, regardless of size. There are no SI ICE at this facility. 

Subpart KKKK, Stationary Combustion Turbines. This subpart affects stationary combustion 

turbines with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBTU) per 

hour, based on the higher heating value of the fuel that commenced construction, modification, 

or reconstruction after February 18, 2005. Stationary combustion turbines regulated under this 

subpart are exempt from the requirements of subpart GG of this part. The turbines at this facility 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 27 

were not constructed, modified, or reconstructed after that date and would not be subject to this 

subpart unless the modifications implementing BART would be considered a modification or 

reconstruction as defined in NSPS, Subpart A. 

NESHAP, 40 CFR Part 61 [Not Applicable] 

There are no emissions of any of the regulated pollutants: arsenic, asbestos, beryllium, benzene, 

coke oven emissions, mercury, radionuclides or vinyl chloride except for trace amounts of 

benzene. Subpart J, Equipment Leaks of Benzene only affects process streams which contain 

more than 10% benzene by weight. All process streams at this facility are below this threshold. 

NESHAP, 40 CFR Part 63 [Not Applicable] 

Subpart YYYY, Combustion Turbines. This subpart was promulgated on March 5, 2004, and 

affects combustion gas turbines that are located at major sources. Emission calculations have 

shown this facility to be a minor source of HAP. 

Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart affects RICE 

with a site-rating greater than 500 brake horsepower that are located at a major source and new 

and reconstructed engines (after June 12, 2006) with a site rating less than or equal to 500 HP 

located at major sources, and for new and reconstructed engines (after June 12, 2006) located at 

area sources. Owners and operators of new or reconstructed engines at area sources and of new 

or reconstructed engines with a site rating equal to or less than 500 HP located at a major source 

(except new or reconstructed 4-stroke lean-burn engines with a site rating greater than or equal to 

250 HP and less than or equal to 500 HP located at a major source) must meet the requirements 

of Subpart ZZZZ by complying with either 40 CFR Part 60 Subpart IIII (for CI engines) or 40 

CFR Part 60 Subpart JJJJ (for SI engines). Based on emission calculations, this facility is a 

minor source of HAP. The 309-hp Cummings NT-855-F (EU AN-ENG1) was constructed prior 

to the applicability dates of this subpart and is not an affected emission unit. 

On March 13, 2009, EPA proposed additional requirements for stationary CI RICE located at 

area sources. A summary of these proposed requirements for engines located at this facility are 

shown below. 

Engine Category Normal Operation (During SSM) @ 15% O2

Existing Emergency CI > 500-hp 40 ppmvd CO or 90% CO reduction (40 ppmvd CO) 

SSM – Startup, Shutdown & Malfunction

The existing CI engine will probably have to be equipped with an oxidation catalyst to meet the 

proposed CO emission limits. 

Subpart DDDDD, National Emission Standards for Hazardous Air Pollutants for Industrial, 

Commercial and Institutional Boilers and Process Heaters. In March, 2007, the EPA filed a 

motion to vacate and remand this rule back to the agency. The rule was vacated by court order, 

subject to appeal, on June 8, 2007. No appeals were made and the rule was vacated on July 30, 

2007. Existing and new small gaseous fuel boilers and process heaters (less than 10 MMBtu/hr 

heat rating) were not subject to any standards, recordkeeping, or notifications under Subpart 

DDDDD. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 28 

EPA is planning on issuing guidance (or a rule) on what actions applicants and permitting 

authorities should take regarding MACT determinations under either Section112(g) or Section 

112(j) for sources that were affected sources under Subpart DDDDD and other vacated MACTs. 

It is expected that the guidance (or rule) will establish a new timeline for submission of section 

112(j) applications for vacated MACT standards. At this time, AQD has determined that a 

112(j) determination is not needed for sources potentially subject to a vacated MACT, including 

Subpart DDDDD. This permit may be reopened to address Section 112(j) when necessary. This 

facility is not a major source of HAP. 

CAM, 40 CFR Part 64 [Not Applicable] 

Compliance Assurance Monitoring (CAM), as published in the Federal Register on October 22, 

1997, applies to any pollutant specific emission unit at a major source, that is required to obtain a 

Title V permit, if it meets all of the following criteria: 

• It is subject to an emission limit or standard for an applicable regulated air pollutant 

• It uses a control device to achieve compliance with the applicable emission limit or standard 

• It has potential emissions, prior to the control device, of the applicable regulated air 

pollutant of 100 TPY 

The two new boilers in EUG 1 are subject to an emission limit (NSPS, Subpart Db, § 

60.44b(a)(1)(ii), 0.2 lb/MMBTU) and they use a control device to achieve compliance with the 

applicable emission limit (Flue gas recirculation systems are considered a control device under 

CAM), but they do not have potential emissions prior to the control device of the applicable 

pollutant of 100 TPY. The two emission units are limited to 100 TPY of CO combined. The 

boilers are also exempt because they are applicable to NSPS, Subpart Db, which requires a 

continuous compliance determination method to determine compliance with the emission limit. 

None of the other emission units use a control device to achieve compliance with an applicable 

emission limit or standard. EU AN-UNIT3 is subject to the requirements of 40 CFR 75 (Acid 

Rain) and is also exempt from additional CAM requirements. However, Specific Condition No. 

4 requires recordkeeping of operation and maintenance activities for EU AN-UNIT3 through 

AN-UNIT6. Specific Condition 5 requires testing, every five years, of the exhaust gases from 

the emission units in EUG 3 for NOX and CO. Specific Condition No. 6 requires reporting of 

excess emissions if emissions from EUG 1 or 2 exceed the limits of Specific Condition No. 1. 

Currently, WFEC is not proposing to use a control device to comply with BART. If it is 

determined that a control device is necessary, WFEC will be required to submit a modification to 

incorporate any applicable requirements. 

Chemical Accident Prevention Provisions, 40 CFR Part 68 [Applicable] 

This facility does not store any regulated substance above the applicable threshold limits. More 

information on this federal program is available at the web site: http://www.epa.gov/ceppo/. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 29 

Acid Rain, 40 CFR Part 72 (Permit Requirements) [Applicable] 

The facility submitted a Phase II Monitoring Plan on December 15, 1995, and subsequently 

submitted a revised application on March 1, 1996. EPA issued a certificate of approval for the 

Continuous Emission Monitoring System (CEM) for EU AN-UNIT3 in March 1999. A separate 

Acid Rain Permit, No. 97-059-AR, was issued on April 15, 1999. The acid rain renewal permit, 

Permit No. 2004-189-ARR, was issued on November 23, 2004. The Acid Rain permit contained 

all of the Acid Rain requirements for EU AN-UNIT3. EUs AN-UNIT1 and AN-UNIT2 serve 

generators with a nameplate capacity below the threshold level of 25 MWe and are therefore 

exempt from these requirements. 

Acid Rain, 40 CFR Part 75 (Monitoring Requirements) [Applicable] 

EUs AN-UNIT1 and AN-UNIT2 serve generators with a nameplate capacity below the threshold 

level of 25 MWe and are therefore exempt from these requirements. EUs AN-UNIT4, ANUNIT5, and AN-UNIT6 are combined cycle gas turbines and do not meet the definition of an 

affected unit under the Acid Rain Program. EU AN-UNIT3 is the only affected unit and must 

meet the monitoring requirements of the Acid Rain Program whenever it is operated (typically 

only one week per year for preventative maintenance and testing purposes). 

Stratospheric Ozone Protection, 40 CFR Part 82 [Subparts A and F are Applicable] 

These standards require phase out of Class I & II substances, reductions of emissions of Class I 

& II substances to the lowest achievable level in all use sectors, and banning use of nonessential 

products containing ozone-depleting substances (Subparts A & C); control servicing of motor 

vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations 

which meet phase out requirements and which maximize the substitution of safe alternatives to 

Class I and Class II substances (Subpart D); require warning labels on products made with or 

containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon 

disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds 

under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons 

(Subpart H). 

Subpart A identifies ozone-depleting substances and divides them into two classes. Class I 

controlled substances are divided into seven groups; the chemicals typically used by the 

manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform 

(Class I, Group V). A complete phase-out of production of Class I substances is required by 

January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are 

hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs. 

Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances, 

scheduled in phases starting by 2002, is required by January 1, 2030. 

Subpart F requires that any persons servicing, maintaining, or repairing appliances except for 

motor vehicle air conditioners; persons disposing of appliances, including motor vehicle air 

conditioners; refrigerant reclaimers, appliance owners, and manufacturers of appliances and 

recycling and recovery equipment comply with the standards for recycling and emissions 

reduction. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 30 

Conditions are included in the standard conditions of the permit to address the requirements 

specified at §82.156 for persons opening appliances for maintenance, service, repair, or disposal; 

§82.158 for equipment used during the maintenance, service, repair, or disposal of appliances; 

§82.161 for certification by an approved technician certification program of persons performing 

maintenance, service, repair, or disposal of appliances; §82.166 for recordkeeping; § 82.158 for 

leak repair requirements; and §82.166 for refrigerant purchase records for appliances normally 

containing 50 or more pounds of refrigerant. 

SECTION X. COMPLIANCE 

Inspection 

On November 8, 2002, Laura Herron of Air Quality and other Air Quality personnel performed a 

compliance inspection. Mr. Gerald Butcher, Environmental Supervisor for Western Farmers 

Electric Cooperative and other Anadarko Plant personnel were present for the inspection. Only 

one combined cycle gas turbine was operating. The facility existed as described in the permit 

application and supplemental materials. 

Testing 

Testing conducted on November 16 and 17, 2004, shows compliance with the established permit 

limits. 

 Permit Limitations Test Results 

 Load Heat Input NOX CO NOX CO

Source (MW) (MMBTUH) lb/hr lb/hr lb/hr lb/hr 

AN-UNIT4 50.4 480.0 580.0 93.7 112.2 7.6 

 

AN-UNIT5 50.8 471.5 580.0 93.7 123.5 3.8 

AN-UNIT6 54.3 537.9 580.0 93.7 139.8 2.9 

Tier Classification and Public Review 

This application has been determined to be Tier II based on the request for a significant 

modification of a Part 70 operating permit. The permittee has submitted an affidavit that they 

are not seeking a permit for land use or for any operation upon land owned by others without 

their knowledge. The affidavit certifies that the applicant owns the land. 

The applicant published the “Notice of Filing a Tier II Application” in The Anadarko Public 

News, a daily newspaper, in Caddo County on February 26, 2009. The notice stated that the 

application was available for public review at the Anadarko Public Library located at 215 West 

Broadway Anadarko, Oklahoma and was also available for review at the Air Quality Division 

main office. The applicant will publish the "Notice of Tier II Draft Permit" in The Anadarko 

Public News, a daily newspaper, in Caddo County on April 17, 2010. The notice stated that the 

draft permit was available for public review at the Anadarko Public Library located at 215 West 

Broadway Anadarko, Oklahoma and was also available for review at the Air Quality Division 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 31 

main office and on the Air Quality section of the DEQ Web Page: http://www.deq.state.ok.us/. 

No comments were received from the public. However, the applicant has requested a change to 

the wording of Specific Condition 1, EUG 3 (b) to indicate that the facility is authorized to burn 

very low sulfur fuel oil during testing for emergency preparedness. Specific Condition 1, EUG 3 

(b) was changed as follows {emphasis added}: 

Wording from Draft Permit: 

a. Prior to the BART Compliance Date, EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall 

be fueled with commercial-grade natural gas but may be fueled with fuel oil, for Scenario 

II - up to the approved maximum firing rates and maximum fuel oil sulfur contents 

indicated below. On and after the BART Compliance Date, EUs AN-UNIT4, AN-UNIT5, 

and AN-UNIT6 shall be fueled with commercial-grade natural gas but may be fueled with 

fuel oil during emergencies, with a maximum sulfur content of 15 ppmw, during 

emergencies. “Emergencies” are defined as: [OAC 252:100-31] 

i. extreme and unusual fuel supply circumstances which prevent adequate supply of fuel 

(natural gas) to the facility; and 

ii. such circumstances are the result of a natural disaster, an Act of God, an equipment 

failure associated with a pipeline, compressor station, or gas plant, and which could 

not have been reasonably foreseen or prevented. 

Proposed Wording: 

b. Prior to the BART Compliance Date, EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall 

be fueled with commercial-grade natural gas but may be fueled with fuel oil, for Scenario 

II - up to the approved maximum firing rates and maximum fuel oil sulfur contents 

indicated below. On and after the BART Compliance Date, EUs AN-UNIT4, AN-UNIT5, 

and AN-UNIT6 shall be fueled with commercial-grade natural gas but may be fueled with 

fuel oil, with a maximum sulfur content of 15 ppmw, during emergencies and short term 

periods for testing for emergency preparedness. “Emergencies” are defined as: 

 [OAC 252:100-31] 

i. extreme and unusual fuel supply circumstances which prevent adequate supply of fuel 

(natural gas) to the facility; and 

ii. such circumstances are the result of a natural disaster, an Act of God, an equipment 

failure associated with a pipeline, compressor station, or gas plant, and which could 

not have been reasonably foreseen or prevented. 

State Review 

This facility is not located within 50 miles of the Oklahoma border. 

EPA Review 

The proposed permit was forwarded to EPA Region VI for a 45-day review period. No 

comments were received from the EPA. 

Fees Paid

Part 70 operating permit significant modification application fee of $1,000. 
PERMIT MEMORANDUM 2005-037-TVR (M-2) Page 32 

SECTION XI. SUMMARY 

The facility is operating as stated in the application. Ambient air quality standards are not 

threatened at this site. There are no active Air Quality compliance or enforcement issues 

concerning this facility. Issuance of the operating permit is recommended. 
 

PERMIT TO OPERATE 

AIR POLLUTION CONTROL FACILITY 

SPECIFIC CONDITIONS 

Western Farmers Electric Cooperative Permit Number 2005-037-TVR (M-2) 

Anadarko Power Plant 

The permittee is authorized to operate in conformity with the specifications submitted to Air 

Quality on September 6, 1996, June 19, 2003, January 31, 2005, and March 20, 2007 and all 

supplemental materials. The Evaluation Memorandum, dated September 9, 2010, explains the 

derivation of applicable permit requirements and estimates of emissions; however, it does not 

contain operating limitations or permit requirements. Continuing operations under this permit 

constitutes acceptance of, and consent to, the conditions contained herein: 

1. Points of emissions and limitations for each point: [OAC 252:100-8-6(a)(1)] 

EUG 1: Emission limitations for emission units (EUs) AN-UNIT1R and AN-UNIT2R. 

Emission Unit 

Units NOX CO 

AN-UNIT1R lb/hr 7.8 33.5 

TPY 11.3 48.5 

lb/MMBTU 0.2 

AN-UNIT2R lb/hr 7.8 33.5 

TPY 11.3 48.5 

lb/MMBTU 0.2 

a. The permittee shall be authorized to operate AN-UNIT1R and AN-UNIT2R up to a 

maximum combined total of 5,800 hours per 12-month period. [OAC 252:100-8-6(a)] 

b. AN-UNIT1R and AN-UNIT2R shall only be fired with commercial-grade natural gas. 

 [OAC 252:100-31] 

c. Each emission unit AN-UNIT1R and AN-UNIT2R shall have a permanent identification 

plate attached which shows the make, model number, and serial number. 

 [OAC 252:100-43] 

d. EU AN-UNIT1R and AN-UNIT2R are subject to New Source Performance Standards, 40 

CFR 60, Subpart Db, and shall comply with all applicable requirements. 

 [§§ 60.40b through 60.49b] 

(1) Except as provided under § 60.44b (k), on and after the date on which the initial 

performance test is completed or is required to be completed under § 60.8, whichever 

date comes first, no owner or operator of an affected facility that is subject to the 

provisions of this section and that combusts only natural gas shall cause to be 

discharged into the atmosphere from that affected facility any gases that contain 

nitrogen oxides (expressed as NO2) in excess of the following emission limit: 

(i) High heat release rate: 86 ng/J (0.20 lb/million Btu) [§ 60.44b(a)(1)] 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 2

(2) For purposes of § 60.44b (i), the nitrogen oxide standards under this section apply at 

all times including periods of startup, shutdown, or malfunction. [§ 60.44b(h)] 

(3) Except as provided under § 60.44b (j), compliance with the emission limits is 

determined on a 30-day rolling average basis. [§ 60.44b(i)] 

(4) The nitrogen oxides emission standards under § 60.44b apply at all times. 

 [§ 60.46b(a)] 

(5) Compliance with the nitrogen oxides emission standards under § 60.44b shall be 

determined through performance testing under § 60.46b(e). [§ 60.46b(c)] 

(6) To determine compliance with the emission limits for nitrogen oxides required under 

§ 60.44b, the owner or operator of an affected facility shall conduct the performance 

test as required under § 60.8 using the continuous system for monitoring nitrogen 

oxides under § 60.48(b). [§ 60.46b(e)] 

(i) For the initial compliance test, nitrogen oxides from the steam generating unit 

are monitored for 30 successive steam generating unit operating days and the 

30-day average emission rate is used to determine compliance with the nitrogen 

oxides emission standards under § 60.44b. The 30-day average emission rate is 

calculated as the average of all hourly emissions data recorded by the 

monitoring system during the 30-day test period. [§ 60.46b(e)(1)] 

(ii) Following the date on which the initial performance test is completed or 

required to be completed under § 60.8, whichever date comes first, the owner or 

operator of an affected facility which has a heat input capacity of 73 MW (250 

million Btu/hour) or less and which combusts natural gas, distillate oil, or 

residual oil having a nitrogen content of 0.30 weight percent or less shall upon 

request determine compliance with the nitrogen oxides standards under § 60.44b 

through the use of a 30-day performance test. During periods when 

performance tests are not requested, nitrogen oxides emissions data collected 

pursuant to § 60.48b(g)(1) or § 60.48b(g)(2) are used to calculate a 30-day 

rolling average emission rate on a daily basis and used to prepare excess 

emission reports, but will not be used to determine compliance with the nitrogen 

oxides emission standards. A new 30-day rolling average emission rate is 

calculated each steam generating unit operating day as the average of all of the 

hourly nitrogen oxides emission data for the preceding 30 steam generating unit 

operating days. [§ 60.46b(e)(4)] 

(7) Except as provided under paragraphs § 60.48b(g), (h), and (i), the owner or operator 

of an affected facility subject to the nitrogen oxides standards under § 60.44b shall 

install, calibrate, maintain, and operate a continuous monitoring system for measuring 

nitrogen oxides emissions discharged to the atmosphere and record the output of the 

system. [§ 60.48b(b)] 

(8) The continuous monitoring systems required under § 60.48b(b) shall be operated and 

data recorded during all periods of operation of the affected facility except for 

continuous monitoring system breakdowns and repairs. Data is recorded during 

calibration checks, and zero and span adjustments. [§ 60.48b(c)] 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 3

(9) The 1-hour average nitrogen oxides emission rates measured by the continuous 

nitrogen oxides monitor required by § 60.48b(b) and required under § 60.13(h) shall 

be expressed in ng/J or lb/million Btu heat input and shall be used to calculate the 

average emission rates under § 60.44b. The 1-hour averages shall be calculated using 

the data points required under § 60.13(b). At least 2 data points must be used to 

calculate each 1-hour average. [§ 60.48b(d)] 

(10) The procedures under § 60.13 shall be followed for installation, evaluation, and 

operation of the continuous monitoring systems. [§ 60.48b(e)] 

(i) For affected facilities combusting natural gas the span value for nitrogen oxides 

is 500 ppm. [§ 60.48b(e)(2)] 

(11) When nitrogen oxides emission data are not obtained because of continuous 

monitoring system breakdowns, repairs, calibration checks and zero and span 

adjustments, emission data will be obtained by using standby monitoring systems, 

Method 7, Method 7A, or other approved reference methods to provide emission data 

for a minimum of 75 percent of the operating hours in each steam generating unit 

operating day, in at least 22 out of 30 successive steam generating unit operating 

days. [§ 60.48b(f)] 

(12) The owner or operator of each affected facility shall submit notification of the date of 

initial startup, as provided by § 60.7. This notification shall include: [§ 60.49b(a)] 

(i) The design heat input capacity of the affected facility and identification of the 

fuels to be combusted in the affected facility, 

(ii) If applicable, a copy of any Federally enforceable requirement that limits the 

annual capacity factor for any fuel or mixture of fuels under §§ 60.44b(c), (d), 

(e), (i), (j), (k), or 60.48b(i), and 

(iii) The annual capacity factor at which the owner or operator anticipates operating 

the facility based on all fuels fired and based on each individual fuel fired. 

(13) The owner or operator of each affected facility subject to the nitrogen oxides 

emission limits under § 60.44b shall submit to the Administrator the performance test 

data from the initial performance test and the performance evaluation of the CEMS 

using the applicable performance specifications in appendix B. [§ 60.49b(b)] 

(14) The owner or operator of each affected facility subject to the nitrogen oxides standard 

of § 60.44b who seeks to demonstrate compliance with those standards through the 

monitoring of steam generating unit operating conditions under the provisions of § 

60.48b(g)(2) shall submit to the Administrator for approval a plan that identifies the 

operating conditions to be monitored under § 60.48b(g)(2) and the records to be 

maintained under § 60.49b(j). This plan shall be submitted to the DEQ for approval 

within 360 days of the initial startup of the affected facility. The plan shall: 

 [§ 60.49b(c)] 

(i) Identify the specific operating conditions to be monitored and the relationship 

between these operating conditions and nitrogen oxides emission rates (i.e., ng/J 

or lbs/million Btu heat input). Steam generating unit operating conditions 

include, but are not limited to, the degree of staged combustion (i.e., the ratio of 

primary air to secondary and/or tertiary air) and the level of excess air (i.e., flue 

gas oxygen level); 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 4

(ii) Include the data and information that the owner or operator used to identify the 

relationship between nitrogen oxides emission rates and these operating 

conditions; 

(iii) Identify how these operating conditions, including steam generating unit load, 

will be monitored under § 60.48b(g) on an hourly basis by the owner or operator 

during the period of operation of the affected facility; the quality assurance 

procedures or practices that will be employed to ensure that the data generated 

by monitoring these operating conditions will be representative and accurate; 

and the type and format of the records of these operating conditions, including 

steam generating unit load, that will be maintained by the owner or operator 

under § 60.49b(j). If the plan is approved, the owner or operator shall maintain 

records of predicted nitrogen oxide emission rates and the monitored operating 

conditions, including steam generating unit load, identified in the plan. 

(15) The owner or operator of an affected facility shall record and maintain records of the 

amount of natural gas combusted each day and calculate the annual capacity factor 

for each calendar quarter. The annual capacity factor is determined on a 12-month 

rolling average basis with a new annual capacity factor calculated at the end of each 

calendar month. [§ 60.49b(d)] 

(16) Except as provided under § 60.49b(p), the owner or operator of an affected facility 

subject to the nitrogen oxides standards under § 60.44b shall maintain records of the 

following information for each steam generating unit operating day: [§ 60.49b(g)] 

(i) Calendar date. 

(ii) The average hourly nitrogen oxides emission rates (expressed as NO2) (ng/J or 

lb/million Btu heat input) measured or predicted. 

(iii) The 30-day average nitrogen oxides emission rates (ng/J or lb/million Btu heat 

input) calculated at the end of each steam generating unit operating day from the 

measured or predicted hourly nitrogen oxide emission rates for the preceding 30 

steam generating unit operating days. 

(iv) Identification of the steam generating unit operating days when the calculated 

30-day average nitrogen oxides emission rates are in excess of the nitrogen 

oxides emissions standards under § 60.44b, with the reasons for such excess 

emissions as well as a description of corrective actions taken. 

(v) Identification of the steam generating unit operating days for which pollutant 

data have not been obtained, including reasons for not obtaining sufficient data 

and a description of corrective actions taken. 

(vi) Identification of the times when emission data have been excluded from the 

calculation of average emission rates and the reasons for excluding data. 

(vii) Identification of ‘‘F’’ factor used for calculations, method of determination, and 

type of fuel combusted. 

(viii) Identification of the times when the pollutant concentration exceeded full span 

of the continuous monitoring system. 

(ix) Description of any modifications to the continuous monitoring system that 

could affect the ability of the continuous monitoring system to comply with 

Performance Specification 2 or 3. 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 5

(x) Results of daily CEMS drift tests and quarterly accuracy assessments as 

required under appendix F, Procedure 1. 

(17) The owner or operator of any affected facility in any category listed in paragraphs § 

60.49b(h)(1) or (2) is required to submit excess emission reports for any calendar 

quarter during which there are excess emissions from the affected facility. If there 

are no excess emissions during the calendar quarter, the owner or operator shall 

submit a report semiannually stating that no excess emissions occurred during the 

semiannual reporting period. [§ 60.49b(h)] 

(i) Any affected facility subject to the opacity standards under § 60.43b(e) or to the 

operating parameter monitoring requirements under § 60.13(i)(1). 

(ii) Any affected facility that is subject to the nitrogen oxides standard of § 60.44b, 

and that (i) Combusts natural gas, distillate oil, or residual oil with a nitrogen 

content of 0.3 weight percent or less, or (ii) Has a heat input capacity of 73 MW 

(250 million Btu/hour) or less and is required to monitor nitrogen oxides 

emissions on a continuous basis under § 60.48b(g)(1) or steam generating unit 

operating conditions under § 60.48b(g)(2). 

(iii) For purposes of § 60.48b(g)(1), excess emissions are defined as any calculated 

30-day rolling average nitrogen oxides emission rate, as determined under § 

60.46b(e), which exceeds the applicable emission limits in § 60.44b. 

1. The owner or operator of any affected facility subject to the 

continuous monitoring requirements for nitrogen oxides under § 

60.48(b) shall submit a quarterly report containing the information 

recorded under paragraph (g) of this section. All quarterly reports 

shall be postmarked by the 30th day following the end of each 

calendar quarter. 

(18) All records required under § 60.49b shall be maintained by the owner or operator of 

the affected facility for a period of 2 years following the date of such record. 

 [§ 60.49b(o)] 

EUG 2: EU AN-UNIT3 is “grandfathered” (constructed prior to May 31, 1972). The 

equipment is limited to the existing equipment as it is. 

EU Manufacturer MMBTUH MW 

Serial 

Number 

AN-UNIT3 Riley Stoker 531 44 3333 

a. EU AN-UNIT3 shall only be fired with commercial-grade natural gas. 

 [OAC 252:100-31] 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 6

EUG 3: Emission limitations for emission units (EUs) AN-UNIT4, AN-UNIT5, and ANUNIT6. 

Scenario I (Natural Gas)

Permitted Emissions

Emission Unit Units NOX CO VOC PM10 SO2

AN-UNIT4 lb/hr 580.0 93.7 20.5 35.7 0.5

TPY 2,239.1 410.5 89.6 156.4 2.4

AN-UNIT5 lb/hr 580.0 93.7 20.5 35.7 0.5

TPY 2,239.1 410.5 89.6 156.4 2.4

AN-UNIT6 lb/hr 580.0 93.7 20.5 35.7 0.5

TPY 2,239.1 410.5 89.6 156.4 2.4

Scenario II (Fuel Oil No. 2)

Emission Unit Permitted Emissions 

Units NOX CO VOC PM10 SO2

AN-UNIT4 lb/hr 630.5 40.9 14.5 52.0 74.43

TPY 2,761.5 179.1 63.4 227.6 326.00

AN-UNIT5 lb/hr 630.5 40.9 14.5 52.0 74.43

TPY 2,761.5 179.1 63.4 227.6 326.00

AN-UNIT6 lb/hr 630.5 40.9 14.5 52.0 74.43

TPY 2,761.5 179.1 63.4 227.6 326.00

Scenario III (BART)

Permitted Emissions

Emission Unit Units NOX CO VOC PM10 SO2

AN-UNIT4 lb/hr1 170.0 93.7 20.5 6.7 0.6

TPY 744.6 410.5 89.6 29.3 2.6

AN-UNIT5 lb/hr1 170.0 93.7 20.5 6.7 0.6

TPY 744.6 410.5 89.6 29.3 2.6

AN-UNIT6 lb/hr1 170.0 93.7 20.5 6.7 0.6

TPY 744.6 410.5 89.6 29.3 2.6

1

 – Based on a 24-hour average. 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 7

c. The permittee shall conduct daily visual observations of the opacity from the exhausts 

associated with emission units burning fuel oil No. 2 and keep a record of these 

observations. If visible emissions are detected, then the permittee shall conduct a thirtyminute opacity reading in accordance with EPA Reference Method No. 9. 

 [OAC 252:100-25] 

d. Prior to the BART Compliance Date, EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall 

be fueled with commercial-grade natural gas but may be fueled with fuel oil, for Scenario 

II - up to the approved maximum firing rates and maximum fuel oil sulfur contents 

indicated below. On and after the BART Compliance Date, EUs AN-UNIT4, AN-UNIT5, 

and AN-UNIT6 shall be fueled with commercial-grade natural gas but may be fueled with 

fuel oil, with a maximum sulfur content of 15 ppmw, during emergencies and short term 

periods for testing for emergency preparedness. “Emergencies” are defined as: 

 [OAC 252:100-31] 

i. extreme and unusual fuel supply circumstances which prevent adequate supply of fuel 

(natural gas) to the facility; and 

ii. such circumstances are the result of a natural disaster, an Act of God, an equipment 

failure associated with a pipeline, compressor station, or gas plant, and which could 

not have been reasonably foreseen or prevented. 

e. The “BART Compliance Date” shall mean the date no later than five (5) years after EPA’s 

approval of Oklahoma’s regional haze State Implementation Plan (SIP) incorporating the 

BART requirements, as published in the Federal Register. 

f. When firing fuel oil in EU AN-UNIT4, AN-UNIT5, and AN-UNIT6, as authorized by 

Scenario II, the permittee shall determine the sulfur content of the fuel oil being combusted 

and not exceed the following maximum fuel oil firing rates based on the fuel oil sulfur 

content and the number of units being fired with fuel oil. The fuel oil sulfur content can be 

determined using the following methods: a current lab analysis or a supplier’s delivery 

ticket. 

Fuel Oil 

% Sulfur 

Maximum Firing 

Rate When 3 Units 

Are Operating 

(gal/hr/unit) 

Fuel Oil 

% Sulfur 

Maximum Firing 

Rate When 2 Units 

Are Operating 

(gal/hr/unit) 

Fuel Oil 

% Sulfur 

Maximum 

Firing Rate 

For 1 Unit 

(gal/hr) 

0.340 1,000 

0.330 1,100 

0.320 1,200 

0.310 1,300 

0.185 1,000 0.300 1,400 

0.180 1,100 0.290 1,500 

0.140 1,000 0.175 1,200 0.280 1,600 

0.135 1,100 0.170 1,300 0.275 1,700 

0.130 1,200 0.165 1,400 0.270 1,800 

0.125 1,300 0.160 1,500 0.265 2,000 

0.120 1,500 0.155 1,600 0.260 2,100 

0.115 1,700 0.150 1,900 0.255 2,300 

0.110 2,000 0.145 2,200 0.250 2,700 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 8

Fuel Oil 

% Sulfur 

Maximum Firing 

Rate When 3 Units 

Are Operating 

(gal/hr/unit) 

Fuel Oil 

% Sulfur 

Maximum Firing 

Rate When 2 Units 

Are Operating 

(gal/hr/unit) 

Fuel Oil 

% Sulfur 

Maximum 

Firing Rate 

For 1 Unit 

(gal/hr) 

0.105 2,500 0.140 2,800 0.245 4,600 

0.100 5,000 0.135 4,600 0.240 4,800 

0.095 5,300 0.130 4,900 0.235 5,000 

0.090 5,700 0.125 5,200 0.230 5,200 

0.085 6,100 0.120 5,500 0.225 5,300 

0.080 6,500 0.115 5,700 0.220 5,400 

0.110 6,000 0.215 5,600 

0.105 6,500 0.210 5,700 

0.205 5,900 

0.200 6,100 

0.195 6,200 

0.190 6,500 

EUG 4: Emission limitations for EU AN-ENG1. EU AN-ENG1 shall not be operated more 

than 500 hours per 12-month period. 

Permitted Emissions 

Emission Unit Units NOX CO VOC 

AN-ENG1 lb/hr 8.93 2.33 0.29 

309-hp Cummings TPY 39 10 1.27 

EUG 5: Storage tank VOC emissions are estimated based on existing equipment 

items but do not have a specific limitation. 

Point Contents Barrels Gallons 

T-1 Fuel Oil No. 2 443 18,600 

T-3 Fuel Oil No. 2 109,524 4,600,000 

T-4 Fuel Oil No. 2 109,524 4,600,000 

T-5 Unleaded Gasoline (UST) 238 10,000 

T-6 Unleaded Gasoline (UST) 238 10,000 

T-7 Diesel Fuel (UST) 286 12,000 

T-8 Condensate 298 12,500 

T-10 Lube Oil 71 3,000 

T-11 Mineral Oil 71 3,000 

T-12 Mineral Oil 71 3,000 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 9

2. The permittee shall be authorized to operate this facility continuously (24 hours per day, 

every day of the year) except as provided above. [OAC 252:100-8-6(a)] 

3. Each emission unit at the facility (EUs AN-UNIT1 through AN-UNIT6 and AN-ENG1) 

shall have a permanent identification plate attached which shows the make, model number, and 

serial number. [OAC 252:100-43] 

4. The permittee shall keep operation and maintenance (O&M) records for the 

“grandfathered” emission unit identified in EUG 2 and the combined cycle gas turbines in EUG 

3. Such records shall at a minimum include the dates of operation, and maintenance, type of 

work performed, and the increase, if any, in emissions as a result. [OAC 252:100-8-6 (a)(3)(B)] 

5. At least every five years, the permittee shall conduct tests of NOX and CO concentrations in 

exhaust gases from AN-UNIT4 through AN-UNIT6 when operating under representative 

conditions for that period. Testing shall be conducted using approved reference methods and 

shall be submitted with the Title V permit renewal application. [OAC 252:100-8-6 (a)(3)(A)] 

6. When operational data of the combined cycle gas turbines shows concentrations in excess 

of the established emission limits (in excess of lb/hr and lb/MMBTU), the owner or operator 

shall comply with the provisions of OAC 252:100-9. [OAC 252:100-9] 

7. The facility is subject to Acid Rain Program and shall comply with all applicable 

requirements including the following: 

a. SO2 actual emissions shall be equal to or less than allowances held. 

b. Report quarterly emissions to EPA per 40 CFR 75. 

c. Maintain a QA/QC plan for maintenance of the monitoring system. 

8. Replacement (including temporary periods of 6 months or less for maintenance purposes, 

etc.), of the emergency pump engine with one of lesser or equal emissions of each pollutant (in 

lb/hr and TPY) is authorized under the following conditions: [OAC 252:100-8-6 (a)(3)(A)] 

a. The permittee shall notify AQD in writing at least 7 days in advance of the 

replacement. Said notice shall include the new engine make and model, horsepower 

rating, fuel usage, stack flow (ACFM), stack temperature (o

F), stack height (feet), 

stack diameter (inches), and pollutant emission rates (g/hp-hr, lbs/hr, and TPY) at 

maximum rated horsepower for the altitude/location. 

9. The following records shall be maintained on-site to verify Insignificant Activities. No 

recordkeeping is required for those operations which qualify as Trivial Activities. 

 [OAC 252:100-8-6 (a)(3)(B)] 

a. For fuel storage/dispensing equipment operated solely for facility owned vehicles: Records 

of the type and amount of fuel dispensed (annual).
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 10

b. For fluid storage tanks with a capacity of less than 39,894 gallons and a true vapor pressure 

less than 1.5 psia: Records of the capacity of the tanks and the contents.

c. For crude oil and condensate storage tanks with a capacity of less than or equal to 420,000 

gallons that store crude oil and condensate prior to custody transfer: Records of capacity of 

the tanks and the amount of throughput (annual). 

d. For activities (except for trivial activities) that have the potential to emit less than 5.0 TPY 

(actual) of any criteria pollutant: The type of activity and the amount of emissions or a 

surrogate measure of the activity (annual). 

10. The permittee shall maintain records of operations as listed below. These records shall be 

maintained on-site for at least five years after the date of recording and shall be provided to 

regulatory personnel upon request. [OAC 252:100-8-6 (a)(3)(B)] 

a. Total natural gas and/or distillate fuel oil usage for each boiler and each combined 

cycle gas turbine (annual). 

b. Operating hours for the EU AN-UNIT1R, AN-UNIT2R, AN-ENG1 (monthly 12-

month rolling totals). 

c. Operation, maintenance, and inspection log for EU AN-UNIT3 through AN-UNIT6. 

d. Unit load for each combined cycle gas turbine. 

e. Fuel oil sulfur content when firing fuel oil (analysis or delivery tickets). 

f. Records of the date and time of visual emission observations, stack or emission point 

observed, operational status of the emission unit, observed results and conclusions, and 

Reference Method No. 9 results. 

11. No later than 30 days after each anniversary date of the issuance of the original Title V 

permit (June 26, 2000), the permittee shall submit to Air Quality Division of DEQ, with a copy 

to the US EPA, Region 6, a certification of compliance with the terms and conditions of this 

permit. [OAC 252:100-8-6 (c)(5)(A) & (D)] 

12. The Permit Shield (Standard Conditions, Section VI) is extended to the following 

requirements that have been determined to be inapplicable to this facility or the listed emissions 

units: [OAC 252:100-8-6(d)(2)] 

a. NSPS, Subpart D, Solid Fossil Fuel-Fired Steam Generators; 

b. NSPS, Subpart Da, Electric Utility Steam Generating Units; 

c. NSPS, Subpart GG, Stationary Gas Turbines; 

d. AN-UNIT1R, AN-UNIT2R, and AN-UNIT4 through AN-UNIT6 are not subject to 40 

CFR Part 72, Acid Rain Permit Application; and 

e. Emission units AN-UNIT3 through AN-UNIT 6 are not subject to OAC 252:100-33, 

Control of Emissions of Nitrogen Oxides. 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 11

13. The turbines in EUG 3 (EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6) are exempt from 

Best Available Retrofit Technology (BART) requirements of 40 CFR Part 51, Subpart P, as long 

as the facility complies with the following applicable requirements: 

 [40 CFR §§ 51.300-309 & Part 51, Appendix Y] 

a. EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall meet the following emission limits 

no later than the BART Compliance Date as defined in Specific Condition 1, EUG 3, 

(c). 

 NOX PM10

2

 SO2

EU lb/hr1 TPY lb/hr1 TPY lb/hr1 TPY 

AN-UNIT4 170.0 744.6 6.7 29.3 0.6 2.6 

AN-UNIT5 170.0 744.6 6.7 29.3 0.6 2.6 

AN-UNIT6 170.0 744.6 6.7 29.3 0.6 2.6 

1

 – 24-hour rolling average; 

2

 – includes condensable/filterable PM.

b. The permittee shall apply for and obtain a construction permit prior to modification of 

the turbines if the modifications will result in a significant emission increase and a 

significant net emission increase of a regulated NSR pollutant. After modification, the 

facility shall apply for and obtain an operating permit modification to remove any 

emission limit in excess of the above emission limits. 

c. The emission limits above shall apply at all times on or after the BART Compliance Date 

unless otherwise modified. 

d. Unit operating day shall have the same meaning as in 40 CFR Part 60, Subpart KKKK. 

e. Within 60 days of achieving the maximum production rate at which EUs AN-UNIT4, ANUNIT5, and AN-UNIT6 will be operated to meet the above established emission limits, not 

to exceed 180 days after the BART Compliance Date, the permittee shall conduct 

performance testing as follows and furnish a written report to Air Quality. Such report 

shall document compliance with the above emission limits for EUs AN-UNIT4, ANUNIT5, and AN-UNIT6. [OAC 252:100-8-6(a)] 

i. The permittee shall conduct NOX, PM10, and CO testing on the turbines at 60% and 

100% of the maximum capacity. NOX and CO testing shall also be conducted at least 

one additional intermediate point in the operating range. 

ii. Performance testing shall be conducted while the units are operating within 10% of 

the desired testing rates. A testing protocol describing how the testing will be 

performed shall be provided to the AQD for review and approval at least 30 days 

prior to the start of such testing. The permittee shall also provide notice of the actual 

test date to AQD. 

iii. The following USEPA methods shall be used for testing of emissions, unless 

otherwise approved by Air Quality: 

Method 1: Sample and Velocity Traverses for Stationary Sources. 

Method 2: Determination of Stack Gas Velocity and Volumetric Flow 

Rate. 
SPECIFIC CONDITIONS 2005-037-TVR (M-2) Page 12

Method 3: Gas Analysis for Carbon Dioxide, Excess Air, and Dry 

Molecular Weight. 

Method 4: Determination of Moisture in Stack Gases. 

Method 10: Determination of Carbon Monoxide Emissions from 

Stationary Sources. 

Method 6C: Quality Assurance Procedures (Range and Sensitivity, 

Measurement System Performance Specification, and 

Measurement System Performance Test Procedures) shall 

be used in conducting Method 10. 

Method 20: Determination of Nitrogen Oxides and Oxygen Emissions 

from Stationary Gas Turbines. 

Method 201/201A: Determination of PM10 Emissions. 

Method 202: Determination of Condensable Particulate Emissions. 

14. This permit supersedes all previous Air Quality permits for this facility, except for 

construction Permit No. 2005-037-C (M-2), which are now null and void. 
Western Farmers Electric Cooperative 

Attn: Mr. Gerald Butcher 

Environmental Coordinator 

701 NE 7th Street 

Anadarko, OK 73005-0429 

SUBJECT: Permit 2005-037-TVR (M-2) 

Anadarko Power Plant 

 Location: Section 14-T7N- R10W, Caddo County, Oklahoma 

Dear Mr. Butcher: 

Enclosed is the permit authorizing operation of the referenced facility. Please note that this 

permit is issued subject to the certain standards and specific conditions that are attached. These 

conditions must be carefully followed since they define the limits of the permit and will be 

confirmed by periodic inspections. 

Also note that you are required to annually submit an emissions inventory for this facility. An 

emissions inventory must be completed on approved AQD forms and submitted (hardcopy or 

electronically) by March 1st of every year. Any questions concerning the form or submittal 

process should be referred to the Emissions Inventory Staff at 405-702-4100. 

If you have any questions, refer to the permit number above and contact Eric Milligan at 

eric.milligan@deq.ok.gov or at (405) 702-4217. Thank you for your cooperation. 

Sincerely, 

Eric L. Milligan, P.E. 

Engineering Section 

AIR QUALITY DIVISION 

Enclosures 

MAJOR SOURCE AIR QUALITY PERMIT 

STANDARD CONDITIONS

(July 21, 2009)

SECTION I. DUTY TO COMPLY

A. This is a permit to operate / construct this specific facility in accordance with the federal 

Clean Air Act (42 U.S.C. 7401, et al.) and under the authority of the Oklahoma Clean Air Act 

and the rules promulgated there under. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112] 

B. The issuing Authority for the permit is the Air Quality Division (AQD) of the Oklahoma 

Department of Environmental Quality (DEQ). The permit does not relieve the holder of the 

obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or 

ordinances. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112] 

C. The permittee shall comply with all conditions of this permit. Any permit noncompliance 

shall constitute a violation of the Oklahoma Clean Air Act and shall be grounds for enforcement 

action, permit termination, revocation and reissuance, or modification, or for denial of a permit 

renewal application. All terms and conditions are enforceable by the DEQ, by the 

Environmental Protection Agency (EPA), and by citizens under section 304 of the Federal Clean 

Air Act (excluding state-only requirements). This permit is valid for operations only at the 

specific location listed. 

 [40 C.F.R. §70.6(b), OAC 252:100-8-1.3 and OAC 252:100-8-6(a)(7)(A) and (b)(1)] 

D. It shall not be a defense for a permittee in an enforcement action that it would have been 

necessary to halt or reduce the permitted activity in order to maintain compliance with the 

conditions of the permit. However, nothing in this paragraph shall be construed as precluding 

consideration of a need to halt or reduce activity as a mitigating factor in assessing penalties for 

noncompliance if the health, safety, or environmental impacts of halting or reducing operations 

would be more serious than the impacts of continuing operations. [OAC 252:100-8-6(a)(7)(B)] 

SECTION II. REPORTING OF DEVIATIONS FROM PERMIT TERMS

A. Any exceedance resulting from an emergency and/or posing an imminent and substantial 

danger to public health, safety, or the environment shall be reported in accordance with Section 

XIV (Emergencies). [OAC 252:100-8-6(a)(3)(C)(iii)(I) & (II)] 

B. Deviations that result in emissions exceeding those allowed in this permit shall be reported 

consistent with the requirements of OAC 252:100-9, Excess Emission Reporting Requirements. 

 [OAC 252:100-8-6(a)(3)(C)(iv)] 

C. Every written report submitted under this section shall be certified as required by Section III 

(Monitoring, Testing, Recordkeeping & Reporting), Paragraph F. 

 [OAC 252:100-8-6(a)(3)(C)(iv)] 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 2

SECTION III. MONITORING, TESTING, RECORDKEEPING & REPORTING

A. The permittee shall keep records as specified in this permit. These records, including 

monitoring data and necessary support information, shall be retained on-site or at a nearby field 

office for a period of at least five years from the date of the monitoring sample, measurement, 

report, or application, and shall be made available for inspection by regulatory personnel upon 

request. Support information includes all original strip-chart recordings for continuous 

monitoring instrumentation, and copies of all reports required by this permit. Where appropriate, 

the permit may specify that records may be maintained in computerized form. 

 [OAC 252:100-8-6 (a)(3)(B)(ii), OAC 252:100-8-6(c)(1), and OAC 252:100-8-6(c)(2)(B)] 

B. Records of required monitoring shall include: 

(1)the date, place and time of sampling or measurement; 

(2)the date or dates analyses were performed; 

(3)the company or entity which performed the analyses; 

(4)the analytical techniques or methods used; 

(5)the results of such analyses; and 

(6)the operating conditions existing at the time of sampling or measurement. 

 [OAC 252:100-8-6(a)(3)(B)(i)] 

C. No later than 30 days after each six (6) month period, after the date of the issuance of the 

original Part 70 operating permit or alternative date as specifically identified in a subsequent Part 

70 operating permit, the permittee shall submit to AQD a report of the results of any required 

monitoring. All instances of deviations from permit requirements since the previous report shall 

be clearly identified in the report. Submission of these periodic reports will satisfy any reporting 

requirement of Paragraph E below that is duplicative of the periodic reports, if so noted on the 

submitted report. [OAC 252:100-8-6(a)(3)(C)(i) and (ii)] 

D. If any testing shows emissions in excess of limitations specified in this permit, the owner or 

operator shall comply with the provisions of Section II (Reporting Of Deviations From Permit 

Terms) of these standard conditions. [OAC 252:100-8-6(a)(3)(C)(iii)] 

E. In addition to any monitoring, recordkeeping or reporting requirement specified in this 

permit, monitoring and reporting may be required under the provisions of OAC 252:100-43, 

Testing, Monitoring, and Recordkeeping, or as required by any provision of the Federal Clean 

Air Act or Oklahoma Clean Air Act. [OAC 252:100-43] 

F. Any Annual Certification of Compliance, Semi Annual Monitoring and Deviation 

Report, Excess Emission Report, and Annual Emission Inventory submitted in accordance with 

this permit shall be certified by a responsible official. This certification shall be signed by a 

responsible official, and shall contain the following language: “I certify, based on information 

and belief formed after reasonable inquiry, the statements and information in the document are 

true, accurate, and complete.” 

 [OAC 252:100-8-5(f), OAC 252:100-8-6(a)(3)(C)(iv), OAC 252:100-8-6(c)(1), OAC 

252:100-9-7(e), and OAC 252:100-5-2.1(f)] 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 3

G. Any owner or operator subject to the provisions of New Source Performance Standards 

(“NSPS”) under 40 CFR Part 60 or National Emission Standards for Hazardous Air Pollutants 

(“NESHAPs”) under 40 CFR Parts 61 and 63 shall maintain a file of all measurements and other 

information required by the applicable general provisions and subpart(s). These records shall be 

maintained in a permanent file suitable for inspection, shall be retained for a period of at least 

five years as required by Paragraph A of this Section, and shall include records of the occurrence 

and duration of any start-up, shutdown, or malfunction in the operation of an affected facility, 

any malfunction of the air pollution control equipment; and any periods during which a 

continuous monitoring system or monitoring device is inoperative. 

 [40 C.F.R. §§60.7 and 63.10, 40 CFR Parts 61, Subpart A, and OAC 252:100, Appendix Q] 

H. The permittee of a facility that is operating subject to a schedule of compliance shall submit 

to the DEQ a progress report at least semi-annually. The progress reports shall contain dates for 

achieving the activities, milestones or compliance required in the schedule of compliance and the 

dates when such activities, milestones or compliance was achieved. The progress reports shall 

also contain an explanation of why any dates in the schedule of compliance were not or will not 

be met, and any preventive or corrective measures adopted. [OAC 252:100-8-6(c)(4)] 

I. All testing must be conducted under the direction of qualified personnel by methods 

approved by the Division Director. All tests shall be made and the results calculated in 

accordance with standard test procedures. The use of alternative test procedures must be 

approved by EPA. When a portable analyzer is used to measure emissions it shall be setup, 

calibrated, and operated in accordance with the manufacturer’s instructions and in accordance 

with a protocol meeting the requirements of the “AQD Portable Analyzer Guidance” document 

or an equivalent method approved by Air Quality. 

 [OAC 252:100-8-6(a)(3)(A)(iv), and OAC 252:100-43] 

J. The reporting of total particulate matter emissions as required in Part 7 of OAC 252:100-8 

(Permits for Part 70 Sources), OAC 252:100-19 (Control of Emission of Particulate Matter), and 

OAC 252:100-5 (Emission Inventory), shall be conducted in accordance with applicable testing 

or calculation procedures, modified to include back-half condensables, for the concentration of 

particulate matter less than 10 microns in diameter (PM10). NSPS may allow reporting of only 

particulate matter emissions caught in the filter (obtained using Reference Method 5). 

K. The permittee shall submit to the AQD a copy of all reports submitted to the EPA as required 

by 40 C.F.R. Part 60, 61, and 63, for all equipment constructed or operated under this permit 

subject to such standards. [OAC 252:100-8-6(c)(1) and OAC 252:100, Appendix Q] 

SECTION IV. COMPLIANCE CERTIFICATIONS

A. No later than 30 days after each anniversary date of the issuance of the original Part 70 

operating permit or alternative date as specifically identified in a subsequent Part 70 operating 

permit, the permittee shall submit to the AQD, with a copy to the US EPA, Region 6, a 

certification of compliance with the terms and conditions of this permit and of any other 

applicable requirements which have become effective since the issuance of this permit. 

 [OAC 252:100-8-6(c)(5)(A), and (D)] 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 4

B. The compliance certification shall describe the operating permit term or condition that is the 

basis of the certification; the current compliance status; whether compliance was continuous or 

intermittent; the methods used for determining compliance, currently and over the reporting 

period. The compliance certification shall also include such other facts as the permitting 

authority may require to determine the compliance status of the source. 

 [OAC 252:100-8-6(c)(5)(C)(i)-(v)] 

C. The compliance certification shall contain a certification by a responsible official as to the 

results of the required monitoring. This certification shall be signed by a responsible official, 

and shall contain the following language: “I certify, based on information and belief formed 

after reasonable inquiry, the statements and information in the document are true, accurate, and 

complete.” [OAC 252:100-8-5(f) and OAC 252:100-8-6(c)(1)] 

D. Any facility reporting noncompliance shall submit a schedule of compliance for emissions 

units or stationary sources that are not in compliance with all applicable requirements. This 

schedule shall include a schedule of remedial measures, including an enforceable sequence of 

actions with milestones, leading to compliance with any applicable requirements for which the 

emissions unit or stationary source is in noncompliance. This compliance schedule shall 

resemble and be at least as stringent as that contained in any judicial consent decree or 

administrative order to which the emissions unit or stationary source is subject. Any such 

schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the 

applicable requirements on which it is based, except that a compliance plan shall not be required 

for any noncompliance condition which is corrected within 24 hours of discovery. 

 [OAC 252:100-8-5(e)(8)(B) and OAC 252:100-8-6(c)(3)] 

SECTION V. REQUIREMENTS THAT BECOME APPLICABLE DURING THE 

PERMIT TERM 

The permittee shall comply with any additional requirements that become effective during the 

permit term and that are applicable to the facility. Compliance with all new requirements shall 

be certified in the next annual certification. [OAC 252:100-8-6(c)(6)] 

SECTION VI. PERMIT SHIELD 

A. Compliance with the terms and conditions of this permit (including terms and conditions 

established for alternate operating scenarios, emissions trading, and emissions averaging, but 

excluding terms and conditions for which the permit shield is expressly prohibited under OAC 

252:100-8) shall be deemed compliance with the applicable requirements identified and included 

in this permit. [OAC 252:100-8-6(d)(1)] 

B. Those requirements that are applicable are listed in the Standard Conditions and the Specific 

Conditions of this permit. Those requirements that the applicant requested be determined as not 

applicable are summarized in the Specific Conditions of this permit. [OAC 252:100-8-6(d)(2)] 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 5

SECTION VII. ANNUAL EMISSIONS INVENTORY & FEE PAYMENT

The permittee shall file with the AQD an annual emission inventory and shall pay annual fees 

based on emissions inventories. The methods used to calculate emissions for inventory purposes 

shall be based on the best available information accepted by AQD. 

 [OAC 252:100-5-2.1, OAC 252:100-5-2.2, and OAC 252:100-8-6(a)(8)] 

SECTION VIII. TERM OF PERMIT

A. Unless specified otherwise, the term of an operating permit shall be five years from the date 

of issuance. [OAC 252:100-8-6(a)(2)(A)] 

B. A source’s right to operate shall terminate upon the expiration of its permit unless a timely 

and complete renewal application has been submitted at least 180 days before the date of 

expiration. [OAC 252:100-8-7.1(d)(1)] 

C. A duly issued construction permit or authorization to construct or modify will terminate and 

become null and void (unless extended as provided in OAC 252:100-8-1.4(b)) if the construction 

is not commenced within 18 months after the date the permit or authorization was issued, or if 

work is suspended for more than 18 months after it is commenced. [OAC 252:100-8-1.4(a)] 

D. The recipient of a construction permit shall apply for a permit to operate (or modified 

operating permit) within 180 days following the first day of operation. [OAC 252:100-8-4(b)(5)] 

SECTION IX. SEVERABILITY 

The provisions of this permit are severable and if any provision of this permit, or the application 

of any provision of this permit to any circumstance, is held invalid, the application of such 

provision to other circumstances, and the remainder of this permit, shall not be affected thereby. 

 [OAC 252:100-8-6 (a)(6)] 

SECTION X. PROPERTY RIGHTS 

A. This permit does not convey any property rights of any sort, or any exclusive privilege. 

 [OAC 252:100-8-6(a)(7)(D)] 

B. This permit shall not be considered in any manner affecting the title of the premises upon 

which the equipment is located and does not release the permittee from any liability for damage 

to persons or property caused by or resulting from the maintenance or operation of the equipment 

for which the permit is issued. [OAC 252:100-8-6(c)(6)] 

SECTION XI. DUTY TO PROVIDE INFORMATION

A. The permittee shall furnish to the DEQ, upon receipt of a written request and within sixty 

(60) days of the request unless the DEQ specifies another time period, any information that the 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 6

DEQ may request to determine whether cause exists for modifying, reopening, revoking, 

reissuing, terminating the permit or to determine compliance with the permit. Upon request, the 

permittee shall also furnish to the DEQ copies of records required to be kept by the permit. 

 [OAC 252:100-8-6(a)(7)(E)] 

B. The permittee may make a claim of confidentiality for any information or records submitted 

pursuant to 27A O.S. § 2-5-105(18). Confidential information shall be clearly labeled as such 

and shall be separable from the main body of the document such as in an attachment. 

 [OAC 252:100-8-6(a)(7)(E)] 

C. Notification to the AQD of the sale or transfer of ownership of this facility is required and 

shall be made in writing within thirty (30) days after such sale or transfer. 

 [Oklahoma Clean Air Act, 27A O.S. § 2-5-112(G)] 

SECTION XII. REOPENING, MODIFICATION & REVOCATION

A. The permit may be modified, revoked, reopened and reissued, or terminated for cause. 

Except as provided for minor permit modifications, the filing of a request by the permittee for a 

permit modification, revocation and reissuance, termination, notification of planned changes, or 

anticipated noncompliance does not stay any permit condition. 

 [OAC 252:100-8-6(a)(7)(C) and OAC 252:100-8-7.2(b)] 

B. The DEQ will reopen and revise or revoke this permit prior to the expiration date in the 

following circumstances: [OAC 252:100-8-7.3 and OAC 252:100-8-7.4(a)(2)] 

(1) Additional requirements under the Clean Air Act become applicable to a major source 

category three or more years prior to the expiration date of this permit. No such 

reopening is required if the effective date of the requirement is later than the expiration 

date of this permit. 

(2) The DEQ or the EPA determines that this permit contains a material mistake or that the 

permit must be revised or revoked to assure compliance with the applicable 

requirements. 

(3) The DEQ or the EPA determines that inaccurate information was used in establishing 

the emission standards, limitations, or other conditions of this permit. The DEQ may 

revoke and not reissue this permit if it determines that the permittee has submitted false 

or misleading information to the DEQ. 

(4) DEQ determines that the permit should be amended under the discretionary reopening 

provisions of OAC 252:100-8-7.3(b). 

C. The permit may be reopened for cause by EPA, pursuant to the provisions of OAC 100-8-

7.3(d). [OAC 100-8-7.3(d)] 

D. The permittee shall notify AQD before making changes other than those described in Section 

XVIII (Operational Flexibility), those qualifying for administrative permit amendments, or those 

defined as an Insignificant Activity (Section XVI) or Trivial Activity (Section XVII). The 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 7

notification should include any changes which may alter the status of a “grandfathered source,” 

as defined under AQD rules. Such changes may require a permit modification. 

 [OAC 252:100-8-7.2(b) and OAC 252:100-5-1.1] 

E. Activities that will result in air emissions that exceed the trivial/insignificant levels and that 

are not specifically approved by this permit are prohibited. [OAC 252:100-8-6(c)(6)] 

SECTION XIII. INSPECTION & ENTRY 

A. Upon presentation of credentials and other documents as may be required by law, the 

permittee shall allow authorized regulatory officials to perform the following (subject to the 

permittee's right to seek confidential treatment pursuant to 27A O.S. Supp. 1998, § 2-5-105(18) 

for confidential information submitted to or obtained by the DEQ under this section): 

(1) enter upon the permittee's premises during reasonable/normal working hours where a 

source is located or emissions-related activity is conducted, or where records must be 

kept under the conditions of the permit; 

(2) have access to and copy, at reasonable times, any records that must be kept under the 

conditions of the permit; 

(3) inspect, at reasonable times and using reasonable safety practices, any facilities, 

equipment (including monitoring and air pollution control equipment), practices, or 

operations regulated or required under the permit; and 

(4) as authorized by the Oklahoma Clean Air Act, sample or monitor at reasonable times 

substances or parameters for the purpose of assuring compliance with the permit. 

 [OAC 252:100-8-6(c)(2)] 

SECTION XIV. EMERGENCIES 

A. Any exceedance resulting from an emergency shall be reported to AQD promptly but no 

later than 4:30 p.m. on the next working day after the permittee first becomes aware of the 

exceedance. This notice shall contain a description of the emergency, the probable cause of the 

exceedance, any steps taken to mitigate emissions, and corrective actions taken. 

 [OAC 252:100-8-6 (a)(3)(C)(iii)(I) and (IV)] 

B. Any exceedance that poses an imminent and substantial danger to public health, safety, or the 

environment shall be reported to AQD as soon as is practicable; but under no circumstance shall 

notification be more than 24 hours after the exceedance. [OAC 252:100-8-6(a)(3)(C)(iii)(II)] 

C. An "emergency" means any situation arising from sudden and reasonably unforeseeable 

events beyond the control of the source, including acts of God, which situation requires 

immediate corrective action to restore normal operation, and that causes the source to exceed a 

technology-based emission limitation under this permit, due to unavoidable increases in 

emissions attributable to the emergency. An emergency shall not include noncompliance to the 

extent caused by improperly designed equipment, lack of preventive maintenance, careless or 

improper operation, or operator error. [OAC 252:100-8-2] 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 8

D. The affirmative defense of emergency shall be demonstrated through properly signed, 

contemporaneous operating logs or other relevant evidence that: [OAC 252:100-8-6 (e)(2)] 

(1) an emergency occurred and the permittee can identify the cause or causes of the 

emergency; 

(2) the permitted facility was at the time being properly operated; 

(3) during the period of the emergency the permittee took all reasonable steps to minimize 

levels of emissions that exceeded the emission standards or other requirements in this 

permit. 

E. In any enforcement proceeding, the permittee seeking to establish the occurrence of an 

emergency shall have the burden of proof. [OAC 252:100-8-6(e)(3)] 

F. Every written report or document submitted under this section shall be certified as required 

by Section III (Monitoring, Testing, Recordkeeping & Reporting), Paragraph F. 

 [OAC 252:100-8-6(a)(3)(C)(iv)] 

SECTION XV. RISK MANAGEMENT PLAN

The permittee, if subject to the provision of Section 112(r) of the Clean Air Act, shall develop 

and register with the appropriate agency a risk management plan by June 20, 1999, or the 

applicable effective date. [OAC 252:100-8-6(a)(4)] 

SECTION XVI. INSIGNIFICANT ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to 

operate individual emissions units that are either on the list in Appendix I to OAC Title 252, 

Chapter 100, or whose actual calendar year emissions do not exceed any of the limits below. 

Any activity to which a State or Federal applicable requirement applies is not insignificant even 

if it meets the criteria below or is included on the insignificant activities list. 

(1) 5 tons per year of any one criteria pollutant. 

(2) 2 tons per year for any one hazardous air pollutant (HAP) or 5 tons per year for an 

aggregate of two or more HAP's, or 20 percent of any threshold less than 10 tons per year 

for single HAP that the EPA may establish by rule. 

 [OAC 252:100-8-2 and OAC 252:100, Appendix I] 

SECTION XVII. TRIVIAL ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to 

operate any individual or combination of air emissions units that are considered inconsequential 

and are on the list in Appendix J. Any activity to which a State or Federal applicable 

requirement applies is not trivial even if included on the trivial activities list. 

[OAC 252:100-8-2 and OAC 252:100, Appendix J] 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 9

SECTION XVIII. OPERATIONAL FLEXIBILITY

A. A facility may implement any operating scenario allowed for in its Part 70 permit without the 

need for any permit revision or any notification to the DEQ (unless specified otherwise in the 

permit). When an operating scenario is changed, the permittee shall record in a log at the facility 

the scenario under which it is operating. [OAC 252:100-8-6(a)(10) and (f)(1)] 

B. The permittee may make changes within the facility that: 

(1) result in no net emissions increases, 

(2) are not modifications under any provision of Title I of the federal Clean Air Act, and 

(3) do not cause any hourly or annual permitted emission rate of any existing emissions unit 

to be exceeded; 

provided that the facility provides the EPA and the DEQ with written notification as required 

below in advance of the proposed changes, which shall be a minimum of seven (7) days, or 

twenty four (24) hours for emergencies as defined in OAC 252:100-8-6 (e). The permittee, the 

DEQ, and the EPA shall attach each such notice to their copy of the permit. For each such 

change, the written notification required above shall include a brief description of the change 

within the permitted facility, the date on which the change will occur, any change in emissions, 

and any permit term or condition that is no longer applicable as a result of the change. The 

permit shield provided by this permit does not apply to any change made pursuant to this 

paragraph. [OAC 252:100-8-6(f)(2)] 

SECTION XIX. OTHER APPLICABLE & STATE-ONLY REQUIREMENTS 

A. The following applicable requirements and state-only requirements apply to the facility 

unless elsewhere covered by a more restrictive requirement: 

(1) Open burning of refuse and other combustible material is prohibited except as authorized 

in the specific examples and under the conditions listed in the Open Burning Subchapter. 

 [OAC 252:100-13] 

(2) No particulate emissions from any fuel-burning equipment with a rated heat input of 10 

MMBTUH or less shall exceed 0.6 lb/MMBTU. [OAC 252:100-19] 

(3) For all emissions units not subject to an opacity limit promulgated under 40 C.F.R., Part 

60, NSPS, no discharge of greater than 20% opacity is allowed except for: 

 [OAC 252:100-25] 

(a) Short-term occurrences which consist of not more than one six-minute period in any 

consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours. 

In no case shall the average of any six-minute period exceed 60% opacity; 

(b) Smoke resulting from fires covered by the exceptions outlined in OAC 252:100-13-7; 

(c) An emission, where the presence of uncombined water is the only reason for failure 

to meet the requirements of OAC 252:100-25-3(a); or 

(d) Smoke generated due to a malfunction in a facility, when the source of the fuel 

producing the smoke is not under the direct and immediate control of the facility and 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 10

the immediate constriction of the fuel flow at the facility would produce a hazard to 

life and/or property. 

(4) No visible fugitive dust emissions shall be discharged beyond the property line on which 

the emissions originate in such a manner as to damage or to interfere with the use of 

adjacent properties, or cause air quality standards to be exceeded, or interfere with the 

maintenance of air quality standards. [OAC 252:100-29] 

(5) No sulfur oxide emissions from new gas-fired fuel-burning equipment shall exceed 0.2 

lb/MMBTU. No existing source shall exceed the listed ambient air standards for sulfur 

dioxide. [OAC 252:100-31] 

(6) Volatile Organic Compound (VOC) storage tanks built after December 28, 1974, and 

with a capacity of 400 gallons or more storing a liquid with a vapor pressure of 1.5 psia 

or greater under actual conditions shall be equipped with a permanent submerged fill pipe 

or with a vapor-recovery system. [OAC 252:100-37-15(b)] 

(7) All fuel-burning equipment shall at all times be properly operated and maintained in a 

manner that will minimize emissions of VOCs. [OAC 252:100-37-36] 

SECTION XX. STRATOSPHERIC OZONE PROTECTION 

A. The permittee shall comply with the following standards for production and consumption of 

ozone-depleting substances: [40 CFR 82, Subpart A] 

(1) Persons producing, importing, or placing an order for production or importation of certain 

class I and class II substances, HCFC-22, or HCFC-141b shall be subject to the 

requirements of §82.4; 

(2) Producers, importers, exporters, purchasers, and persons who transform or destroy certain 

class I and class II substances, HCFC-22, or HCFC-141b are subject to the recordkeeping 

requirements at §82.13; and 

(3) Class I substances (listed at Appendix A to Subpart A) include certain CFCs, Halons, 

HBFCs, carbon tetrachloride, trichloroethane (methyl chloroform), and bromomethane 

(Methyl Bromide). Class II substances (listed at Appendix B to Subpart A) include 

HCFCs. 

B. If the permittee performs a service on motor (fleet) vehicles when this service involves an 

ozone-depleting substance refrigerant (or regulated substitute substance) in the motor vehicle air 

conditioner (MVAC), the permittee is subject to all applicable requirements. Note: The term 

“motor vehicle” as used in Subpart B does not include a vehicle in which final assembly of the 

vehicle has not been completed. The term “MVAC” as used in Subpart B does not include the 

air-tight sealed refrigeration system used as refrigerated cargo, or the system used on passenger 

buses using HCFC-22 refrigerant. [40 CFR 82, Subpart B] 

C. The permittee shall comply with the following standards for recycling and emissions 

reduction except as provided for MVACs in Subpart B: [40 CFR 82, Subpart F] 

(1) Persons opening appliances for maintenance, service, repair, or disposal must comply 

with the required practices pursuant to § 82.156; 

(2) Equipment used during the maintenance, service, repair, or disposal of appliances must 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 11

comply with the standards for recycling and recovery equipment pursuant to § 82.158; 

(3) Persons performing maintenance, service, repair, or disposal of appliances must be 

certified by an approved technician certification program pursuant to § 82.161; 

(4) Persons disposing of small appliances, MVACs, and MVAC-like appliances must 

comply with record-keeping requirements pursuant to § 82.166; 

(5) Persons owning commercial or industrial process refrigeration equipment must comply 

with leak repair requirements pursuant to § 82.158; and 

(6) Owners/operators of appliances normally containing 50 or more pounds of refrigerant 

must keep records of refrigerant purchased and added to such appliances pursuant to § 

82.166. 

SECTION XXI. TITLE V APPROVAL LANGUAGE 

A. DEQ wishes to reduce the time and work associated with permit review and, wherever it is 

not inconsistent with Federal requirements, to provide for incorporation of requirements 

established through construction permitting into the Source’s Title V permit without causing 

redundant review. Requirements from construction permits may be incorporated into the Title V 

permit through the administrative amendment process set forth in OAC 252:100-8-7.2(a) only if 

the following procedures are followed: 

(1) The construction permit goes out for a 30-day public notice and comment using the 

procedures set forth in 40 C.F.R. § 70.7(h)(1). This public notice shall include notice to 

the public that this permit is subject to EPA review, EPA objection, and petition to 

EPA, as provided by 40 C.F.R. § 70.8; that the requirements of the construction permit 

will be incorporated into the Title V permit through the administrative amendment 

process; that the public will not receive another opportunity to provide comments when 

the requirements are incorporated into the Title V permit; and that EPA review, EPA 

objection, and petitions to EPA will not be available to the public when requirements 

from the construction permit are incorporated into the Title V permit. 

(2) A copy of the construction permit application is sent to EPA, as provided by 40 CFR § 

70.8(a)(1). 

(3) A copy of the draft construction permit is sent to any affected State, as provided by 40 

C.F.R. § 70.8(b). 

(4) A copy of the proposed construction permit is sent to EPA for a 45-day review period 

as provided by 40 C.F.R.§ 70.8(a) and (c). 

(5) The DEQ complies with 40 C.F.R. § 70.8(c) upon the written receipt within the 45-day 

comment period of any EPA objection to the construction permit. The DEQ shall not 

issue the permit until EPA’s objections are resolved to the satisfaction of EPA. 

(6) The DEQ complies with 40 C.F.R. § 70.8(d). 

(7) A copy of the final construction permit is sent to EPA as provided by 40 CFR § 70.8(a). 

(8) The DEQ shall not issue the proposed construction permit until any affected State and 

EPA have had an opportunity to review the proposed permit, as provided by these 

permit conditions. 

(9) Any requirements of the construction permit may be reopened for cause after 

incorporation into the Title V permit by the administrative amendment process, by 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 12

DEQ as provided in OAC 252:100-8-7.3(a), (b), and (c), and by EPA as provided in 40 

C.F.R. § 70.7(f) and (g). 

(10) The DEQ shall not issue the administrative permit amendment if performance tests fail 

to demonstrate that the source is operating in substantial compliance with all permit 

requirements. 

B. To the extent that these conditions are not followed, the Title V permit must go through the 

Title V review process. 

SECTION XXII. CREDIBLE EVIDENCE 

For the purpose of submitting compliance certifications or establishing whether or not a person 

has violated or is in violation of any provision of the Oklahoma implementation plan, nothing 

shall preclude the use, including the exclusive use, of any credible evidence or information, 

relevant to whether a source would have been in compliance with applicable requirements if the 

appropriate performance or compliance test or procedure had been performed. 

 [OAC 252:100-43-6]